CODE OF FEDERAL REGULATIONS
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Title 30—
Redesignation tables appear in the first and second volumes of title 30.
For this volume, Ruth Reedy Green was Chief Editor. The Code of Federal Regulations publication program is under the direction of Frances D. McDonald, assisted by Alomha S. Morris.
(This book contains parts 200 to 699)
Other regulations issued by the Department of the Interior appear in title 25, chapters I and II; title 36, chapter I; title 41, chapter 114; title 43; and title 50, chapters I and IV.
Bureau of Land Management, Department of the Interior, regulations with respect to mineral lands: 43 CFR, chapter II, subchapter C.
Foreign Trade Statistics, Bureau of the Census, Department of Commerce: 15 CFR part 30.
Forest Service regulations relating to mineral developments and mining in national forests: 36 CFR part 228.
General Services Administration regulations for stockpiling of strategic and critical materials: 41 CFR chapter 101, subchapter C.
Interstate Commerce Commission: 49 CFR chapter X.
Bureau of Indian Affairs, Department of the Interior, energy and minerals regulations: 25 CFR chapter I, subchapter I.
(Parts 200 to 699)
The Act of February 25, 1920 (30 U.S.C. 181,
The Associate Director is responsible for the collection of certain rents, royalties, and other payments; for the receipt of sales and production reports; for determining royalty liability; for maintaining accounting records; for any audits of the royalty payments and obligations; and for any and all other functions relating to royalty management on Federal and Indian oil and gas leases.
5 U.S.C. 301
(a) This subpart is applicable to Federal and Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma) and OCS sulfur leases.
(b) The definitions in subparts B, C, D, and E, of part 206 of this title are applicable to subparts B, C, D, and J of this part.
(a) Royalties on oil, gas, and OCS sulfur shall be at the royalty rate specified in the lease, unless the Secretary, pursuant to the provisions of the applicable mineral leasing laws, reduces, or in the case of OCS leases, reduces or eliminates, the royalty rate or net profit share set forth in the lease.
(b) For purposes of this subpart, the use of the term
For leases that provide for minimum royalty payments, the lessee shall pay the minimum royalty as specified in the lease.
(a) Royalties due on oil production from leases subject to the requirements of this part, including condensate separated from gas without processing, shall be at the royalty rate established by the terms of the lease. Royalty shall be paid in value unless MMS requires payment in-kind. When paid in value, the royalty due shall be the value, for royalty purposes, determined pursuant to part 206 of this title multiplied by the royalty rate in the lease.
(b)(1) All oil (except oil unavoidably lost or used on, or for the benefit of, the lease, including that oil used off-lease for the benefit of the lease when such off-lease use is permitted by the MMS or BLM, as appropriate) produced from a Federal or Indian lease to which this part applies is subject to royalty.
(2) When oil is used on, or for the benefit of, the lease at a production facility handling production from more
(3) Where the terms of any lease are inconsistent with this section, the lease terms shall govern to the extent of that inconsistency.
(c) If BLM determines that oil was avoidably lost or wasted from an onshore lease, or that oil was drained from an onshore lease for which compensatory royalty is due, or if MMS determines that oil was avoidably lost or wasted from an offshore lease, then the value of that oil shall be determined in accordance with 30 CFR part 206.
(d) If a lessee receives insurance compensation for unavoidably lost oil, royalties are due on the amount of that compensation. This paragraph shall not apply to compensation through self-insurance.
(e)(1) In those instances where the lessee of any lease committed to a federally approved unitization or communitization agreement does not actually take the proportionate share of the agreement production attributable to its lease under the terms of the agreement, the full share of production attributable to the lease under the terms of the agreement nonetheless is subject to the royalty payment and reporting requirements of this title. Except as provided in paragraph (e)(2) of this section, the value, for royalty purposes, of production attributable to unitized or communitized leases will be determined in accordance with 30 CFR part 206. In applying the requirements of 30 CFR part 206, the circumstances involved in the actual disposition of the portion of the production to which the lessee was entitled but did not take shall be considered as controlling in arriving at the value, for royalty purposes, of that portion as though the person actually selling or disposing of the production were the lessee of the Federal or Indian lease.
(2) If a Federal or Indian lessee takes less than its proportionate share of agreement production, upon request of the lessee MMS may authorize a royalty valuation method different from that required by paragraph (e)(1) of this section, but consistent with the purposes of these regulations, for any volumes not taken by the lessee but for which royalties are due.
(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate share of production in any month under a unitization or communitization agreement shall be deemed to have taken ratably from all persons actually taking less than their proportionate share of the agreement production for that month.
(4) If a lessee takes less than its proportionate share of agreement production for any month but royalties are paid on the full volume of its proportionate share in accordance with the provisions of this section, no additional royalty will be owed for that lease for prior periods when the lessee subsequently takes more than its proportionate share to balance its account or when the lessee is paid a sum of money by the other agreement participants to balance its account.
(f) For production from Federal and Indian leases which are committed to federally-approved unitization or communitization agreements, upon request of a lessee MMS may establish the value of production pursuant to a method other than the method required by the regulations in this title if: (1) The proposed method for establishing value is consistent with the requirements of the applicable statutes, lease terms, and agreement terms; (2) persons with an interest in the agreement, including, to the extent practical, royalty interests, are given notice and an opportunity to comment on the proposed valuation method before it is authorized; and (3) to the extent practical, persons with an interest in a Federal or Indian lease committed to the agreement, including royalty interests, must agree to use the proposed method for valuing production from the agreement for royalty purposes.
Oil volumes are to be reported in barrels of clean oil of 42 standard U.S. gallons (231 cubic inches each) at 60 °F.
(a) Royalties due on gas production from leases subject to the requirements of this subpart, except helium produced from Federal leases, shall be at the rate established by the terms of the lease. Royalty shall be paid in value unless MMS requires payment in kind. When paid in value, the royalty due shall be the value, for royalty purposes, determined pursuant to 30 CFR part 206 of this title multiplied by the royalty rate in the lease.
(b)(1) All gas (except gas unavoidably lost or used on, or for the benefit of, the lease, including that gas used off-lease for the benefit of the lease when such off-lease use is permitted by the MMS or BLM, as appropriate) produced from a Federal lease to which this subpart applies is subject to royalty.
(2) When gas is used on, or for the benefit of, the lease at a production facility handling production from more than one lease with the approval of MMS or BLM, as appropriate, or at a production facility handling unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility may be used royalty free.
(3) Where the terms of any lease are inconsistent with this subpart, the lease terms shall govern to the extent of that inconsistency.
(c) If BLM determines that gas was avoidably lost or wasted from an onshore lease, or that gas was drained from an onshore lease for which compensatory royalty is due, or if MMS determines that gas was avoidably lost or wasted from an OCS lease, then the value of that gas shall be determined in accordance with 30 CFR part 206.
(d) If a lessee receives insurance compensation for unavoidably lost gas, royalties are due on the amount of that compensation. This paragraph shall not apply to compensation through self-insurance.
(e)(1) In those instances where the lessee of any lease committed to a Federally approved unitization or communitization agreement does not actually take the proportionate share of the production attributable to its Federal lease under the terms of the agreement, the full share of production attributable to the lease under the terms of the agreement nonetheless is subject to the royalty payment and reporting requirements of this title. Except as provided in paragraph (e)(2) of this section, the value for royalty purposes of production attributable to unitized or communitized leases will be determined in accordance with 30 CFR part 206. In applying the requirements of 30 CFR part 206, the circumstances involved in the actual disposition of the portion of the production to which the lessee was entitled but did not take shall be considered as controlling in arriving at the value for royalty purposes of that portion, as if the person actually selling or disposing of the production were the lessee of the Federal lease.
(2) If a Federal lessee takes less than its proportionate share of agreement production, upon request of the lessee MMS may authorize a royalty valuation method different from that required by paragraph (e)(1) of this section, but consistent with the purpose of these regulations, for any volumes not taken by the lessee but for which royalties are due.
(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate share of production in any month under a unitization or communitization agreement shall be deemed to have taken ratably from all persons actually taking less than their proportionate share of the agreement production for that month.
(4) If a lessee takes less than its proportionate share of agreement production for any month but royalties are
(f) For production from Federal leases which are committed to federally-approved unitization or communitization agreements, upon request of a lessee MMS may establish the value of production pursuant to a method other than the method required by the regulations in this title if: (1) The proposed method for establishing value is consistent with the requirements of the applicable statutes, lease terms and agreement terms; (2) to the extent practical, persons with an interest in the agreement, including royalty interests, are given notice and an opportunity to comment on the proposed valuation method before it is authorized; and (3) to the extent practical, persons with an interest in a Federal lease committed to the agreement, including royalty interests, must agree to use the proposed method for valuing production from the agreement for royalty purposes.
(a)(1) A royalty, as provided in the lease, shall be paid on the value of:
(i) Any condensate recovered downstream of the point of royalty settlement without resorting to processing; and
(ii) Residue gas and all gas plant products resulting from processing the gas produced from a lease subject to this subpart.
(2) MMS shall authorize a processing allowance for the reasonable, actual costs of processing the gas produced from Federal leases. Processing allowances shall be determined in accordance with 30 CFR part 206 subpart D for gas production from Federal leases and 30 CFR part 206 subpart E for gas production from Indian leases.
(b) A reasonable amount of residue gas shall be allowed royalty free for operation of the processing plant, but no allowance shall be made for boosting residue gas or other expenses incidental to marketing, except as provided in 30 CFR part 206. In those situations where a processing plant processes gas from more than one lease, only that proportionate share of each lease's residue gas necessary for the operation of the processing plant shall be allowed royalty free.
(c) No royalty is due on residue gas, or any gas plant product resulting from processing gas, which is reinjected into a reservoir within the same lease, unit area, or communitized area, when the reinjection is included in a plan of development or operations and the plan has received BLM or MMS approval for onshore or offshore operations, respectively, until such time as they are finally produced from the reservoir for sale or other disposition off-lease.
(a)(1) If you are responsible for reporting production or royalties, you must:
(i) Report gas volumes and British thermal unit (Btu) heating values, if applicable, under the same degree of water saturation;
(ii) Report gas volumes in units of 1,000 cubic feet (mcf); and
(iii) Report gas volumes and Btu heating value at a standard pressure base of 14.73 pounds per square inch absolute (psia) and a standard temperature base of 60 °F.
(2) The frequency and method of Btu measurement as set forth in the lessee's contract shall be used to determine Btu heating values for reporting purposes. However, the lessee shall measure the Btu value at least semiannually by recognized standard industry testing methods even if the lessee's contract provides for less frequent measurement.
(b)(1) Residue gas and gas plant product volumes shall be reported as specified in this paragraph.
(2) Carbon dioxide (CO
(3) Natural gas liquids (NGL) volumes shall be reported in standard U.S. gallons (231 cubic inches) at 60 °F.
(4) Sulfur (S) volumes shall be reported in long tons (2,240 pounds).
The regulations governing overriding royalty interests, production payments, or similar interests created under Federal coal leases are in 43 CFR group 3400.
(a) This subpart is applicable to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970, as amended (30 U.S.C. 1001
(b) The definitions in 30 CFR 206.351 are applicable to this subpart.
(a) Royalties on geothermal resources, including byproduct minerals and commercially demineralized water, shall be at the royalty rate(s) specified in the lease, unless the Secretary of the Interior temporarily waives, suspends, or reduces that rate(s). Royalties shall be paid in value. The royalty due shall be the value determined pursuant to subpart H of 30 CFR part 206 multiplied by the royalty rate in the lease.
(b)(1) Royalties are due on all geothermal resources, except those specified in paragraph (b)(2) of this section, that are produced from a lease and are sold or utilized by the lessee or are reasonably susceptible to sale or utilization by the lessee.
(2) Geothermal resources that are unavoidably lost, as determined by the Bureau of Land Management (BLM), and geothermal resources that are reinjected prior to use on or off the lease, as approved by BLM, are not subject to royalty. The Minerals Management Service (MMS) will allow free of royalty a reasonable amount of geothermal energy necessary to generate electricity for internal powerplant operations or to generate electricity returned to the lease for lease operations. If a powerplant uses geothermal production from more than one lease, or uses unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the powerplant may be used royalty free. The MMS will also allow free of royalty a reasonable amount of commercially demineralized water necessary for powerplant operations or otherwise used on or for the benefit of the lease.
(3) Royalties on byproducts are due at the time the recovered byproduct is used, sold, or otherwise finally disposed of. Byproducts produced and added to stockpiles or inventory do not require payment of royalty until the byproducts are sold, utilized, or otherwise finally disposed of. The MMS may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventories become excessive.
(c) If BLM determines that geothermal resources (including byproducts) were avoidably lost or wasted from the lease, or that geothermal resources (including byproducts) were drained from the lease for which compensatory royalty is due, the value of those geothermal resources shall be determined in accordance with subpart H of 30 CFR part 206.
(d) If a lessee receives insurance or other compensation for unavoidably lost geothermal resources (including byproducts), royalties at the rates specified in the lease are due on the
In no event shall the lessee's annual royalty payments for any producing lease be less than the minimum royalty established by the lease.
(a) For geothermal resources used to generate electricity, the quantity on which royalty is due shall be reported on Form MMS-2014 (Report of Sales and Royalty Remittance) as follows:
(1) For geothermal resources valued under arm's-length or non-arm's-length contracts, quantities shall be reported in:
(i) Kilowatthours to the nearest whole kilowatthour if the contract specifies payment in terms of generated electricity,
(ii) Thousands of pounds to the nearest whole thousand pounds if the contract specifies payment in terms of weight, or
(iii) Millions of Btu's to the nearest whole million Btu if the contract specifies payment in terms of heat or thermal energy.
(2) For geothermal resources valued by the netback procedure pursuant to 30 CFR 206.352(c)(1)(ii) or (d)(1)(ii), the quantities shall be reported in kilowatthours to the nearest whole kilowatthour.
(b) For geothermal resources used in direct utilization processes, the quantity on which royalty is due shall be reported on Form MMS-2014 in:
(1) Millions of Btu's to the nearest whole million Btu if valuation is in terms of thermal energy used or displaced,
(2) Hundreds of gallons to the nearest hundred gallons of geothermal fluid produced if valuation is in terms of volume, or
(3) Other measurement unit approved by MMS for valuation and reporting purposes.
(c) For byproduct minerals, the quantity on which royalty is due shall be reported on Form MMS-2014 consistent with MMS-established reporting standards.
(d) For commercially demineralized water, the quantity on which royalty is due shall be reported on Form MMS-2014 in hundreds of gallons to the nearest hundred gallons.
(e) Lessees are not required to report the quality of geothermal resources, including byproducts, to MMS. The lessee must maintain quality measurements for audit and valuation purposes. Quality measurements include, but are not limited to, temperatures and chemical analyses for fluid geothermal resources and chemical analyses, weight percent, or other purity measurements for byproducts.
If you produce gas from an Indian lease subject to this subpart, you must determine and pay royalties on gas production as specified in this section.
(a)
(b)
(1) The Tribal lessor requires payment in kind; or
(2) You have a lease on allotted lands and MMS requires payment in kind.
(c)
(1) When paid in value, the royalty due is the unit value of production for royalty purposes, determined under 30 CFR part 206, multiplied by the volume of production multiplied by the royalty rate in the lease.
(2) When paid in kind, the royalty due is the volume of production multiplied by the royalty rate.
(d)
(e)
(a) You are liable for royalty on your entitled share of gas production from your Indian lease, except as provided in §§ 202.555, 202.556, and 202.557.
(b) You and all other persons paying royalties on the lease must report and pay royalties based on your takes. If another person takes some of your entitled share but does not pay the royalties owed, you are liable for those royalties.
(c) You and all other persons paying royalties on the lease may ask MMS for permission to report and pay royalties based on your entitlements. In that event, MMS will provide valuation instructions consistent with this part and part 206 of this title.
You must pay royalties each month on production allocated to your lease under the terms of an AFA. To determine the volume and the value of your production, you must follow these three steps:
(a) You must determine the volume of your entitled share of production allocated to your lease under the terms of an AFA. This may include production from more than one AFA.
(b) You must value the production you take using 30 CFR part 206. If you take more than your entitled share of production, see § 202.553 for information on how to value this production. If you take less than your entitled share of production, see § 202.554 for information on how to value production you are entitled to but do not take.
If you take more than your entitled share of production from a lease in an AFA for any month, you must determine the weighted-average value of all of the production that you take using the procedures in 30 CFR part 206, and use that value for your entitled share of production.
If you take none or only part of your entitled production from a lease in an AFA for any month, use this section to value the production that you are entitled to but do not take.
(a) If you take a significant volume of production from your lease during the month, you must determine the weighted average value of the production that you take using 30 CFR part 206, and use that value for the production that you do not take.
(b) If you do not take a significant volume of production from your lease during the month, you must use paragraph (c) or (d) of this section, whichever applies.
(c) In a month where you do not take production or take an insignificant volume, and if you would have used § 206.172(b) to value the production if you had taken it, you must determine the value of production not taken for that month under § 206.172(b) as if you had taken it.
(d) If you take none of your entitled share of production from a lease in an AFA, and if that production cannot be valued under § 206.172(b), then you must determine the value of the production that you do not take using the first of the following methods that applies:
(1) The weighted average of the value of your production (under 30 CFR part 206) in that month from other leases in the same AFA.
(2) The weighted average of the value of your production (under 30 CFR part 206) in that month from other leases in the same field or area.
(3) The weighted average of the value of your production (under 30 CFR part 206) during the previous month for production from leases in the same AFA.
(4) The weighted average of the value of your production (under 30 CFR part 206) during the previous month for production from other leases in the same field or area.
(5) The latest major portion value that you received from MMS calculated under 30 CFR 206.174 for the same MMS-designated area.
(e) You may take less than your entitled share of AFA production for any month, but pay royalties on the full volume of your entitled share under this section. If you do, you will owe no additional royalty for that lease for that month when you later take more than your entitled share to balance your account. The provisions of this paragraph (e) also apply when the other AFA participants pay you money to balance your account.
(a) All gas produced from or allocated to your Indian lease is subject to royalty except the following:
(1) Gas that is unavoidably lost.
(2) Gas that is used on, or for the benefit of, the lease.
(3) Gas that is used off-lease for the benefit of the lease when the Bureau of Land Management (BLM) approves such off-lease use.
(4) Gas used as plant fuel as provided in 30 CFR 206.179(e).
(b) You may use royalty-free only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility when you use gas for one of the following purposes:
(1) On, or for the benefit of, the lease at a production facility handling production from more than one lease with BLM's approval.
(2) At a production facility handling unitized or communitized production.
(c) If the terms of your lease are inconsistent with this subpart, your lease terms will govern to the extent of that inconsistency.
If BLM determines that a volume of gas was avoidably lost or wasted, or a volume of gas was drained from your Indian lease for which compensatory royalty is due, then you must determine the value of that volume of gas under 30 CFR part 206.
If you receive insurance compensation for unavoidably lost gas, you must pay royalties on the amount of that compensation. This paragraph does not apply to compensation through self-insurance.
(a) You must report gas volumes as follows:
(1) Report gas volumes and Btu heating values, if applicable, under the same degree of water saturation. Report gas volumes and Btu heating value at a standard pressure base of 14.73 psia and a standard temperature of 60 degrees Fahrenheit. Report gas volumes in units of 1,000 cubic feet (Mcf).
(2) You must use the frequency and method of Btu measurement stated in your contract to determine Btu heating values for reporting purposes. However, you must measure the Btu value at least semi-annually by recognized standard industry testing methods even if your contract provides for less frequent measurement.
(b) You must report residue gas and gas plant product volumes as follows:
(1) Report carbon dioxide (CO
(2) Report natural gas liquid (NGL) volumes in standard U.S. gallons (231 cubic inches) at 60 degrees F.
(3) Report sulfur (S) volumes in long tons (2,240 pounds).
25 U.S.C. 396
The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law 104-58, authorizes us to grant royalty relief in three situations.
(a) Under 43 U.S.C. 1337(a)(3)(A), we may reduce or eliminate any royalty or a net profit share specified for an OCS lease to promote increased production.
(b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or eliminate any royalty or net profit share to promote development, increase production, or encourage production of marginal resources on certain leases or categories of leases. This authority is restricted to leases in the Gulf of Mexico (GOM) that are west of 87 degrees, 30 minutes West longitude.
(c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for designated volumes of new production from any lease if:
(1) Your lease is in deep water (water at least 200 meters deep);
(2) Your lease is in designated areas of the GOM (west of 87 degrees, 30 minutes West longitude);
(3) Your lease was acquired in a lease sale held before the DWRRA (before November 28, 1995);
(4) We find that your new production would not be economic without royalty relief; and
(5) Your lease is on a field that did not produce before enactment of the DWRRA, or if you propose a project to significantly expand production under a Development Operations Coordination Document (DOCD) or a supplementary DOCD, that MMS approved after November 28, 1995.
We can reduce or suspend royalties for OCS leases or projects that meet the criteria in the following table.
(a) When you submit an application or ask for a preview assessment, you must include a fee to reimburse us for our costs of processing your application or assessment. Federal policy and law require us to recover the cost of services that confer special benefits to identifiable non-Federal recipients. The Independent Offices Appropriation Act (31 U.S.C. 9701), Office of Management and Budget Circular A-25, and the Omnibus Appropriations Bill (Pub. L. 104-133, 110 Stat. 1321, April 26, 1996) authorize us to collect these fees.
(b) We will specify the necessary fees for each of the types of royalty-relief applications and possible MMS audits
The tables in this section summarize how similar provisions in this part apply in different situations.
(a) Provisions relating to application content in §§ 203.51, 203.62 and 203.81 through 203.89.
(b) Provisions relating to verification in §§ 203.70, 203.81 and 203.90 through 203.91.
(c) Provisions relating to approval criteria contained in §§ 203.50, 203.52, 203.60 and 203.67.
(d) Provisions related to redetermination in §§ 203.52 and 203.74 through 203.75.
(e) Provisions related to the format of relief in §§ 203.53 and 203.69.
(f) Provisions related to discontinuing relief §§ 203.54 and 203.78.
(g) Provisions related to the end, loss or reduction of relief in §§ 203.55 and 203.76.
You may apply for royalty relief in two situations.
(a) Your end-of-life lease (as defined in § 203.2) is an oil and gas lease and has average daily production of at least 100 barrels of oil equivalent (BOE) per month (as calculated in § 203.73) in at least 12 of the past 15 months. The most recent of these 12 months are considered the qualifying months. These 12 months should reflect the basic operation you intend to use until your resources are depleted. If you changed your operation significantly (e.g.,
(b) Your end-of-life lease is other than an oil and gas lease (e.g., sulphur) and has production in at least 12 of the past 15 months. The most recent of these 12 months are considered the qualifying months.
You must submit a complete application and the required fee to the appropriate MMS Regional Director. Your MMS regional office will provide specific guidance on the report formats. A complete application for relief includes:
(a) An administrative information report (specified in § 203.83) and
(b) A net revenue and relief justification report (specified in § 203.84).
(a) To qualify for relief, you must demonstrate that the sum of royalty payments over the 12 qualifying months exceeds 75 percent of the sum of net revenues (before-royalty revenues minus allowable costs, as defined in § 203.84).
(b) To re-qualify for relief, e.g., either applying for additional relief on top of relief already granted, or applying for relief sometime after your earlier agreement terminated, you must demonstrate that:
(1) You have met the criterion listed in paragraph (a) of this section, and
(2) The 12 required qualifying months of operation have occurred under the current royalty arrangement.
(a) If we approve your application and you meet certain conditions, we will reduce the pre-application effective royalty rate by one-half on production up to the relief volume amount. If you produce more than the relief volume amount:
(1) We will impose a royalty rate equal to 1.5 times the effective royalty rate on your additional production up to twice the relief volume amount; and
(2) We will impose a royalty rate equal to the effective rate on all production greater than twice the relief volume amount.
(b) Regardless of the level of production or prices (see § 203.54), royalty payments due under end-of-life relief will not exceed the royalty obligations that would have been due at the effective royalty rate.
(1) The effective royalty rate is the average lease rate paid on production during the 12 qualifying months.
(2) The relief volume amount is the average monthly BOE production for the 12 qualifying months.
In those months when your current reference price rises by at least 25 percent above your base reference price, you must pay the effective royalty rate on all monthly production.
(a) Your current reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and natural gas over the most recent full 12 calendar months;
(b) Your base reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and natural gas during the qualifying months; and
(c) Your weighting factors are the proportions of your total production volume (in BOE) provided by oil and gas during the qualifying months.
(a) If you have an end-of-life royalty relief arrangement, you may renounce it at any time. The lease rate will return to the effective rate during the qualifying period in the first full month following our receipt of your renouncement of the relief arrangement.
(b) If you pay the effective lease rate for 12 consecutive months, we will terminate your relief. The lease rate will
(c) We may stipulate in the letter of approval for individual cases certain events that would cause us to terminate relief because they are inconsistent with an end-of-life situation.
Yes. Royalty relief is based on the lease circumstances, not ownership. It transfers upon lease assignment.
Under conditions in §§ 203.61(b) and 203.62, you may apply for royalty relief if:
(a) You are a lessee of a lease in water at least 200 meters deep in the GOM and lying wholly west of 87 degrees, 30 minutes West longitude;
(b) We have assigned your lease to a field (as defined in § 203.0); and
(c) You hold a pre-Act lease on an authorized field (as defined in § 203.0) or you propose an expansion project (as defined in § 203.0).
You may ask for a nonbinding assessment (a formal opinion on whether a field would qualify for royalty relief) before turning in your first complete application on an authorized field. This field must have a qualifying well under 30 CFR part 250, subpart A, or be on a lease that has allocated production under an approved unit agreement.
(a) To request a nonbinding assessment, you must:
(1) Submit a draft application in the format and detail specified in guidance from the MMS regional office for the GOM;
(2) Propose to drill at least one more appraisal well if you get a favorable assessment; and
(3) Pay a fee under § 203.3.
(b) You must wait at least 90 days after receiving our assessment to apply for relief under § 203.62.
(c) This assessment is not binding because a complete application may contain more accurate information that does not support our original assessment. It will help you decide whether your proposed inputs for evaluating economic viability and your supporting data and assumptions are adequate.
At 63 FR 2619, Jan. 16, 1998, § 203.61 was revised. This section contains information collection and recordkeeping requirements and will not become effective until approval has been given by the Office of Management and Budget.
You must send a complete application and the required fee to the MMS GOM Regional Director.
(a) Your application for deep water royalty relief must include an original and two copies (one set of digital information) of:
(1) Administrative information report;
(2) Deep water economic viability and relief justification report;
(3) G&G report;
(4) Engineering report;
(5) Production report; and
(6) Deep water cost report.
(b) Section 203.82 explains why we are authorized to require these reports.
(c) Sections 203.81, 203.83, and 203.85 through 203.89 describe what these reports must include. The MMS GOM Regional Office will guide you on the format for the required reports.
For authorized fields, we will accept only one joint application for all leases that are part of the designated field on the date of application, except as provided in paragraph (c) of this section and § 203.64.
(a) The Regional Director maintains a Field Names Master List with updates of all leases in each designated field.
(b) To avoid sharing proprietary data with other lessees on the field, you may submit your proprietary G&G report separately from the rest of your application. Your application is not complete until we receive all the required information for each lease on
(c) We will not require a joint application if you show good cause and honest effort to get all lessees in the field to participate. If you must exclude a lease from your application because its lessee will not participate, that lease is ineligible for the royalty relief for the designated field.
You may file one complete application for royalty relief during the life of the field. However, you may send another application if:
(a) You are eligible to apply for a redetermination under § 203.74;
(b) You apply for royalty relief for an expansion project;
(c) You withdraw the application before we make a determination; or
(d) You apply for end-of-life royalty relief.
(a) We will determine within 20 working days if your application for royalty relief is complete. If your application is incomplete, we will explain in writing what it needs. If you withdraw a complete application, you may reapply.
(b) We will evaluate your first application on a field within 180 days and a redetermination under § 203.75 within 120 days after we say it is complete.
(c) We may ask to extend the review period for your application under the conditions in the following table.
(d) We may change your assumptions under § 203.62 if our technical evaluation reveals others that are more appropriate. We may consult with you before a final decision and will explain any changes.
(e) We will notify all designated lease operators within a field when royalty relief is granted.
If we do not act within the timeframes established in § 203.65, the conditions in the following table apply.
Your field or project must require royalty relief to be economic and must become economic with this relief. That is, we will not approve applications if we determine that royalty relief cannot make the field or project economically viable.
(a) We will not consider ineligible costs as set forth in § 203.89(h) in determining economic viability for purposes of royalty relief.
(b) We will consider sunk costs (allowable expenditures on and after the discovery well as specified in § 203.89(a)) in accordance with the following table.
This section applies only to leases on which you have applied for and received a royalty-suspension volume under section 302 of the DWRRA. We will not collect royalties on a specified suspension volume for your field. Suspension amounts include volumes allocated to a lease under an approved unit agreement and exclude any volumes that do not bear a royalty under the lease or the regulations of this chapter.
(a) For authorized fields, the minimum royalty-suspension volumes are:
(1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200 to 400 meters of water;
(2) 52.5 MMBOE for fields in 400 to 800 meters of water; and
(3) 87.5 MMBOE for fields in more than 800 meters of water.
(b) If the application for the field includes leases in different categories of water depth, we apply the minimum royalty-suspension volume for the deepest lease then associated with the field. We base the water depth and makeup of a field on the water-depth delineations in the “Royalty Suspension Areas Map” and the Field Names Master List and updates in effect at the time your application is approved. These publications are available from the GOM Regional Office.
(c) You will get a royalty-suspension volume above the minimum if we determine that you need more to make developing the field economic.
(d) For expansion projects, the minimum suspension volumes do not apply. If we determine that your expansion project may be economic only with relief, we will determine and grant you the royalty-suspension volume necessary to make the project economic.
(e) A royalty-suspension volume will continue through the end of the month in which cumulative production reaches that volume. The cumulative production is from all the leases in the authorized field or expansion project that are entitled to share the royalty suspension volume.
You must submit reports to us as indicated in the following table. Sections 203.81 and 203.90 through 203.91 describe what these reports must include. MMS's GOM Regional Office will tell you the formats.
The allocation depends on when production occurs, when the lease is assigned to the field, and whether we award the volume suspension by an approved application or establish it in the lease terms.
(a) If your authorized field has an approved royalty-suspension volume under §§ 203.67 and 203.69, we will suspend payment of royalties on production from all applying leases in the field until their cumulative production equals the approved volume. The following conditions also apply as appropriate:
(b) If your authorized field has an automatic royalty-suspension volume established under § 260.110 of this chapter, we will suspend payment of royalties on production from all eligible leases in the field until their cumulative production equals the automatic volume. The following conditions also apply as appropriate:
(c) If you have an expansion project with more than one lease, the royalty-suspension volume for each lease equals that lease's actual incremental production from the project (or production allocated under an approved unit agreement) until cumulative incremental production for all leases in the project equals the project's approved royalty-suspension volume.
(d) You may receive a royalty-suspension volume only if your entire lease is west of 87 degrees, 30 minutes West longitude. If the field lies on both sides of this meridian, only leases located entirely west of the meridian will receive a royalty-suspension volume.
Yes. You may apply for royalty relief that involves more than one suspension volume under § 203.62 in two circumstances.
(a) Each field that includes your lease may receive a separate royalty-suspension volume, if it meets the evaluation criteria of § 203.67.
(b) An expansion project on your lease may receive a separate royalty-
You must measure natural gas production under the royalty-suspension volume as follows: 5.62 thousand cubic feet of natural gas, measured in accordance with 30 CFR part 250, subpart L, equals one barrel of oil equivalent.
Under certain conditions, you may request a redetermination if we deny your application, if you want your approved royalty-suspension volume to change, after we withdraw approval, or after you renounce royalty relief. To be eligible for a redetermination, at least one of the following three conditions must occur.
(a) You have significant new G&G data and you previously have not either requested a redetermination or reapplied for relief after we withdrew approval or you relinquished royalty relief. “Significant” means that the new G&G data:
(1) Results from drilling new wells or getting new three-dimensional seismic data and information (but not reinterpreting old data);
(2) Did not exist at the time of the earlier application; and
(3) Changes your estimates of gross resource size, quality, or projected flow rates enough to materially affect the results of our earlier determination.
(b) Your current reference price decreases by more than 25 percent from your base reference price. For royalty relief on deep water expansion projects and pre-Act deep water leases:
(1) Your current reference price is a weighted average of daily closing prices on the NYMEX for light sweet crude oil and natural gas over the most recent full 12-calendar months;
(2) Your base reference price is a weighted average of daily closing prices on the NYMEX for oil and gas for the most recent full 12-calendar months preceding the date of your most recent, complete application for this royalty relief; and
(3) The weighting factors are the proportions of the total production volume (in BOE) for oil and gas associated with the most likely scenario (identified in §§ 203.85 and 203.88) from your most recently approved application for this royalty relief.
(c) Before starting to build your development and production system, you have revised your estimated development costs, and they are more than 120 percent of the eligible development costs associated with the most likely scenario from your most recent, complete application for this royalty relief.
If you request a redetermination after we have granted you a suspension volume, you could lose some or all of the previously granted relief. This can happen because you must file a new complete application and pay the required fee, as discussed in § 203.62. We will evaluate your application under § 203.67 using the conditions prevailing at the time of your redetermination request. In our evaluation, we may find that you should receive a larger, equivalent, smaller, or no suspension volume. This means we could find that you do not qualify for the amount of relief previously granted or for any relief at all.
We will withdraw approval of relief for any of the following reasons.
(a) You change the type of development system proposed in your application (e.g., change from a fixed platform to floating production system, tension leg platform to a moored catenary system such as a SPAR platform, an independent development and production system to one with subsea wells tied back to a host production facility, etc.).
(b) You do not start building the proposed development and production system within 1 year of the date we approved your application—unless the MMS Director grants you an extension under § 203.79(c).
(c) You do not tell us in your post-production development report (§ 203.70), and we find out your actual development costs are less than 80 percent of the eligible development costs estimated in your application's most likely scenario. Development costs are those incurred between the application submission date and start of production. If you tell us about this result in the post-production development report, you may retain 50 percent of the original royalty-suspension volume.
(d) We granted you a royalty-suspension volume after you qualified for a redetermination under § 203.74(c), and we find out your actual development costs are less than 90 percent of the eligible development costs associated with your application's most likely scenario. Development costs are those expenditures defined in § 203.89(b) incurred between your application submission date and start of production.
(e) You do not send us the fabrication confirmation report or the post-production development report, or you provide false or intentionally inaccurate information that was material to our granting royalty relief under this section. You must pay royalties and late-payment interest determined under 30 U.S.C. 1721 and § 218.54 of this chapter on all volumes for which you used the royalty suspension. You also may be subject to penalties under other provisions of law.
You may renounce approved royalty-suspension volumes as soon as you anticipate violating one of the withdrawal conditions, or for any other reason, before you start production.
No, you must pay full royalties if prices rise above the statutory base price for light sweet crude oil or natural gas.
(a) Suppose the arithmetic average of the daily closing NYMEX light sweet crude oil prices for the previous calendar year exceeds $28.00 per barrel, as adjusted in paragraph (f) of this section. In this case, we retract the royalty relief authorized in this section and you must:
(1) Pay royalties on all oil production for the previous year at the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and § 218.54 of this chapter) by April 30 of the current calendar year, and
(2) Pay royalties on all your oil production in the current year.
(b) Suppose the arithmetic average of the daily closing NYMEX natural gas prices for the previous calendar year exceeds $3.50 per million British thermal units (Btu), as adjusted in paragraph (f) of this section. In this case, we retract the royalty relief authorized in this section and you must:
(1) Pay royalties on all natural gas production for the previous year at the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and § 218.54 of this chapter) by April 30 of the current calendar year, and
(2) Pay royalties on all your natural gas production in the current year.
(c) Production under both paragraphs (a) and (b) of this section counts as part of the royalty-suspension volume.
(d) You are entitled to a refund or credit, with interest, of royalties paid on any production (that counts as part of the royalty-suspension volume):
(1) Of oil if the arithmetic average of the closing oil prices for the current calendar year is $28.00 per barrel or less, as adjusted in paragraph (f) of this section, and
(2) Of gas if the arithmetic average of the closing natural gas prices for the current calendar year is $3.50 per million Btu or less, as adjusted in paragraph (f) of this section.
(e) You must follow our regulations in part 230 of this chapter for receiving refunds or credits.
(f) We change the prices referred to in paragraphs (a), (b) and (d) of this section during each calendar year after 1994. These prices change by the percentage the implicit price deflator for the gross domestic product changed during the preceding calendar year.
(a) Once we have designated your lease as part of a field and notified you and other affected operators of the designation, you can request reconsideration by sending the MMS Director a letter within 15 days that also states your reasons. The MMS Director's response is the final agency action.
(b) Our decisions on your application for relief from paying royalty under § 203.67 and the royalty-suspension volumes under § 203.69 are final agency actions.
(c) If you cannot start construction by the deadline in § 203.76(b) for reasons beyond your control (e.g., strike at the fabrication yard), you may request an extension up to 1 year by writing the MMS Director and stating your reasons. The MMS Director's response is the final agency action.
(d) We will notify you of all final agency actions by certified mail, return receipt requested. Final agency actions are not subject to appeal to the Interior Board of Land Appeals under 30 CFR part 290 and 43 CFR part 4. They are judicially reviewable under section 10(a) of the Administrative Procedure Act (5 U.S.C. 702)
(a) You must send us the supplemental reports listed below that apply to your field. §§ 203.83 through 203.91 describe these reports in detail.
(b) You must certify that all information in your application, fabricator's confirmation and post-production development reports is accurate, complete, and conforms to the most recent content and presentation guidelines available from the MMS GOM Regional Office.
(c) You must submit with your application and post-production development report an additional report prepared by a CPA that:
(1) Assesses the accuracy of the historical financial information in your report; and
(2) Certifies that the content and presentation of the financial data and information conforms to our most recent guidelines on royalty relief.
(d) You must identify the people in the CPA firm who prepared the reports referred to in paragraph (c) of this section and make them available to us to respond to questions about the historical financial information. We may also further review your records to support this information.
The Office of Management and Budget (OMB) approved the information collection requirements in part 203 under 44 U.S.C. 3501
(a) We use the information to determine whether royalty relief will result in production that wouldn’t otherwise occur. We rely largely on your information to make these determinations.
(1) Your application for royalty relief must contain enough information on finances, economics, reservoirs, G&G characteristics, production, and engineering estimates for us to determine whether:
(i) We should grant relief under the law, and
(ii) The requested relief will ultimately recover more resources and return a reasonable profit on project investments.
(2) Your fabricator confirmation and post-production development reports must contain enough information for us to verify that your application reasonably represented your plans.
(b) Applicants (respondents) are Federal OCS oil and gas lessees. Applications are required to obtain or retain a benefit. Therefore, if you apply for royalty relief, you must provide this information. We will protect information considered proprietary under applicable law and under regulations at § 203.63(b) and part 250 of this chapter.
(c) The Paperwork Reduction Act of 1995 requires us to inform you that we may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
This report identifies the field or lease for which royalty relief is requested and must contain the following items:
(a) The field or lease name;
(b) The serial number of leases we have assigned to the field, names of the lease title holders of record, the lease operators, and whether any lease is part of a unit;
(c) Lessee's designation, the API number and location of each well that has been drilled on the field or lease or project (not required for non-oil and gas leases);
(d) The location of any new wells proposed under the terms of the application (not required for non-oil and gas leases);
(e) A description of field or lease history;
(f) Full information as to whether you will pay royalties or a share of production to anyone other than the United States, the amount you will pay, and how much you will reduce this payment if we grant relief;
(g) The type of royalty relief you are requesting;
(h) Confirmation that we approved a DOCD or supplemental DOCD (Deep Water expansion project applications only); and
(i) A narrative description of the development activities associated with the proposed capital investments and an explanation of proposed timing of the activities and the effect on production (Deep Water applications only).
This report presents cash flow data for 12 qualifying months, using the format specified in the “Guidelines for the Application, Review, Approval, and Administration of Royalty Relief for End-of-Life Leases”, U.S. Department of the Interior, MMS. Qualifying months for an oil and gas lease are the most recent 12 months out of the last 15 months that you produced at least 100 BOE per day on average. Qualifying months for other than oil and gas leases are the most recent 12 of the last 15 months having some production.
(a) The cash flow table you submit must include historical data for:
(1) Lease production subject to royalty;
(2) Total revenues;
(3) Royalty payments out of production;
(4) Total allowable costs; and
(5) Transportation and processing costs.
(b) Do not include in your cash flow table the non-allowable costs listed at 30 CFR 220.013 or:
(1) OCS rental payments on the lease(s) in the application;
(2) Damages and losses;
(3) Taxes;
(4) Any costs associated with exploratory activities;
(5) Civil or criminal fines or penalties;
(6) Fees for your royalty relief application; and
(7) Costs associated with existing obligations (e.g., royalty overrides or other forms of payment for acquiring the lease, depreciation on previously acquired equipment or facilities).
(c) We may, in reviewing and evaluating your application, disallow costs when you have not shown they are necessary to operate the lease, or if they are inconsistent with end-of-life operations.
This report should show that your project appears economic without royalties and sunk costs using the RSVP model we provide. The format of the report and the assumptions and parameters we specify are found in the “Guidelines for the Application, Review, Approval and Administration of the Deep Water Royalty Relief Program,” U.S. Department of the Interior, MMS. Clearly justify each parameter you set in every scenario you specify in the RSVP. You may provide supplemental information, including your own model and results. The economic viability and relief justification report must contain the following items for an oil and gas lease.
(a) Economic assumptions we provide which include:
(1) Starting oil and gas prices;
(2) Real price growth;
(3) Real cost growth or decline rate, if any;
(4) Base year;
(5) Range of discount rates; and
(6) Tax rate (for use in determining after-tax sunk costs).
(b) Analysis of projected cash flow (from the date of the application using annual totals and constant dollar values) which shows:
(1) Oil and gas production;
(2) Total revenues;
(3) Capital expenditures;
(4) Operating costs;
(5) Transportation costs; and
(6) Before-tax net cash flow without royalties, overrides, sunk costs, and ineligible costs.
(c) Discounted values which include:
(1) Discount rate used (selected from within the range we specify).
(2) Before-tax net present value without royalties, overrides, sunk costs, and ineligible costs.
(d) Demonstrations that:
(1) All costs, gross production, and scheduling are consistent with the data in the G&G, engineering, production, and cost reports (§§ 203.86 through 203.89) and
(2) The development and production scenarios provided in the various reports are consistent with each other and with the proposed development system. You can use up to three scenarios (conservative, most likely, and optimistic), but you must link each to a specific range on the distribution of resources from the RSVP Resource Module.
This report supports the reserve and resource estimates used in the economic evaluation and must contain each of the following elements.
(a) Seismic data which includes:
(1) Non-interpreted 2D/3D survey lines reflecting any available state-of-the-art processing technique in a format readable by MMS and specified by the deep water royalty relief guidelines;
(2) Interpreted 2D/3D seismic survey lines reflecting any available state-of-the-art processing technique identifying all known and prospective pay horizons, wells, and fault cuts;
(3) Digital velocity surveys in the format of the GOM region's letter to lessees of 10/1/90;
(4) Plat map of “shot points;” and
(5) “Time slices” of potential horizons.
(b) Well data which includes:
(1) Hard copies of all well logs in which—
(i) The 1-inch electric log shows pay zones and pay counts and lithologic and paleo correlation markers at least every 500-feet,
(ii) The 1-inch type log shows missing sections from other logs where faulting occurs,
(iii) The 5-inch electric log shows pay zones and pay counts and labeled points used in establishing resistivity of the formation, 100 percent water
(iv) The 5-inch porosity logs show pay zones and pay counts and labeled points used in establishing reservoir porosity or labeled points showing values used in calculating reservoir porosity such as bulk density or transit time;
(2) Digital copies of all well logs spudded before December 1, 1995;
(3) Core data, if available;
(4) Well correlation sections;
(5) Pressure data;
(6) Production test results; and
(7) Pressure-volume-temperature analysis, if available.
(c) Map interpretations which includes for each reservoir in the field:
(1) Structure maps consisting of top and base of sand maps showing well and seismic shot point locations;
(2) Isopach maps for net sand, net oil, net gas, all with well locations;
(3) Maps indicating well surface and bottom hole locations, location of development facilities, and shot points; and
(4) Identification of reservoirs not contemplated for development.
(d) Reservoir-specific data which includes:
(1) Probability of reservoir occurrence with hydrocarbons;
(2) Probability the hydrocarbon in the reservoir is all oil and the probability it is all gas;
(3) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for the parameters used to estimate reservoir size, i.e., acres and net thickness;
(4) Most likely values for porosity, salt water saturation, volume factor for oil formation, and volume factor for gas formation;
(5) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for recovery efficiency (in percent) and oil or gas recovery (in stock-tank-barrels per acre-foot or in thousands of cubic feet per acre foot);
(6) A gas/oil ratio distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each reservoir; and
(7) A yield distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each gas reservoir.
(e) Aggregated reserve and resource data which includes:
(1) The aggregated distributions for reserves and resources (in BOE) and oil fraction for your field computed by the resource module of our RSVP model;
(2) A description of anticipated hydrocarbon quality (i.e., specific gravity); and
(3) The ranges within the aggregated distribution for reserves and resources that define the development and production scenarios presented in the engineering and production reports. Typically there will be three ranges specified by two positive reserve and resource points on the aggregated distribution. The range at the low end of the distribution will be associated with the conservative development and production scenario; the middle range will be related to the most likely development and production scenario; and, the high end range will be consistent with the optimistic development and production scenario.
This report defines the development plan and capital requirements for the economic evaluation and must contain the following elements.
(a) A description of the development concept (e.g., tension leg platform, fixed platform, floater type, subsea tieback, etc.) which includes:
(1) Its size and
(2) The construction schedule.
(b) An identification of planned wells which includes:
(1) The number;
(2) The type (platform, subsea, vertical, deviated, horizontal);
(3) The well depth;
(4) The drilling schedule;
(5) The kind of completion (single, dual, horizontal, etc.); and
(6) The completion schedule.
(c) A description of the production system equipment which includes:
(1) The production capacity for oil and gas and a description of limiting component(s);
(2) Any unusual problems (low gravity, paraffin, etc.);
(3) All subsea structures;
(4) All flowlines; and
(5) Schedule for installing the production system.
(d) A discussion of any plans for multi-phase development which includes:
(1) The conceptual basis for developing in phases and goals or milestones required for starting later phases; and
(2) An explanation for excluding the reservoirs you are not planning to develop.
(e) A set of development scenarios consisting of activity timing and scale associated with each of up to three production profiles (conservative, most likely, optimistic) provided in the production report for your field (§ 203.88). Each development scenario and production profile must denote the likely events should the field size turn out to be within a range represented by one of the three segments of the field size distribution. If you send in fewer than three scenarios, you must explain why fewer scenarios are more efficient across the whole field size distribution.
This report supports your development and production timing and product quality expectations and must contain the following elements.
(a) Production profiles by well completion and field that specify the actual and projected production by year for each of the following products: oil, condensate, gas, and associated gas. The production from each profile must be consistent with a specific level of reserves and resources on the aggregated distribution of field size.
(b) Production drive mechanisms for each reservoir.
This report lists all actual and projected costs for your field, must explain and document the source of each cost estimate, and must identify the following elements.
(a) Sunk cost, which are all your eligible post-discovery exploration, development, and production expenses (no third party costs), and also include the eligible costs of the discovery well on the field. Report them in nominal dollars and only if you have documentation. We count sunk costs in an evaluation (specified in § 203.68) as after-tax expenses, using nominal dollar amounts.
(b) Appraisal, delineation and development costs. Base them on actual spending, current authorization for expenditure, engineering estimates, or analogous projects. These costs cover:
(1) Platform well drilling and average depth;
(2) Platform well completion;
(3) Subsea well drilling and average depth;
(4) Subsea well completion;
(5) Production system (platform); and
(6) Flowline fabrication and installation.
(c) Production costs based on historical costs, engineering estimates, or analogous projects. These costs cover:
(1) Operation;
(2) Equipment; and
(3) Existing royalty overrides (we will not use the royalty overrides in evaluations).
(d) Transportation costs, based on historical costs, engineering estimates, or analogous projects. These costs cover:
(1) Oil or gas tariffs from pipeline or tankerage;
(2) Trunkline and tieback lines; and
(3) Gas plant processing for natural gas liquids.
(e) Abandonment costs, based on historical costs, engineering estimates, or analogous projects. You should provide the costs to plug and abandon only wells and to remove only production systems for which you have not incurred costs as of the time of application submission. You should also include a point estimate or distribution of prospective salvage value for all potentially reusable facilities and materials, along with the source and an explanation of the figures provided.
(f) A set of cost estimates consistent with each one of up to three field-development scenarios and production
(g) A spending schedule. You should provide costs for each year (in real dollars) for each category in paragraphs (a) through (f) of this section.
(h) A summary of other costs which are ineligible for evaluating your need for relief. These costs cover:
(1) Expenses before first discovery on the field;
(2) Cash bonuses;
(3) Fees for royalty relief applications;
(4) Lease rentals, royalties, and payments of net profit share and net revenue share;
(5) Legal expenses;
(6) Damages and losses;
(7) Taxes;
(8) Interest or finance charges, including those embedded in equipment leases;
(9) Fines or penalties; and
(10) Money spent on previously existing obligations (e.g., royalty overrides or other forms of payment for acquiring a financial position in a lease, expenditures for plugging wells and removing and abandoning facilities that existed on the application submission date).
This report shows you have committed in a timely way to the approved system for production. This report must include the following (or its equivalent for unconventionally acquired systems):
(a) A copy of the contract(s) under which the fabrication yard is building the approved system for you;
(b) A letter from the contractor building the system to the MMS's GOM Regional Supervisor—Production and Development, certifying when construction started on your system; and
(c) Evidence of an appropriate down payment or equal action that you’ve started acquiring the approved system.
For each cost category in the deep water cost report, you must compare actual costs up to the date when production starts to your planned pre-production costs. If your application included more than one development scenario, you need to compare actual costs with those in your scenario of most likely development. Keep supporting records for these costs and make them available to us on request.
Provisions for the payment of advance royalty in lieu of continued operation are contained at 43 CFR 3483.4.
An application for reduction in coal royalty rate or rental shall be filed and processed in accordance with 43 CFR group 3400.
5 U.S.C. 301
The information collection requirements contained in this part have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10.
(a) This subpart is applicable to all oil production from Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma). The purpose of this subpart is to establish the value of production, for royalty purposes, consistent with the mineral leasing laws, other applicable laws, and lease terms.
(b) If the specific provisions of any Federal statute, treaty, settlement agreement between the Indian lessor and a lessee resulting from administrative or judicial litigation, or oil and gas lease subject to the requirements of this subpart are inconsistent with any regulation in this subpart, then the statute, treaty, lease provision or settlement agreement shall govern to the extent of that inconsistency.
(c) All royalty payments made to MMS or Indian Tribes are subject to audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian oil and gas leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.
For the purposes of this subpart:
(a)(1) The value of production, for royalty purposes, of oil from leases subject to this subpart shall be the value determined under this section less applicable allowances determined under this subpart.
(2)(i) For any Indian leases which provide that the Secretary may consider the highest price paid or offered for a major portion of production (major portion) in determining value for royalty purposes, if data are available to compute a major portion, MMS will, where practicable, compare the value determined in accordance with this section with the major portion. The value to be used in determining the value of production, for royalty purposes, shall be the higher of those two values.
(ii) For purposes of this paragraph, major portion means the highest price paid or offered at the time of production for the major portion of oil production from the same field. The major portion will be calculated using like-quality oil sold under arm's-length contracts from the same field (or, if necessary to obtain a reasonable sample, from the same area) for each month. All such oil production will be arrayed from highest price to lowest price (at the bottom).
The major portion is that price at which 50 percent (by volume) plus 1 barrel of the oil (starting from the bottom) is sold.
(b)(1)(i) The value of oil which is sold under an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit. For purposes of this section, oil which is sold or otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate under an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate.
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the oil. If the contract does not reflect the total consideration, then MMS may require that the oil sold under that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration.
(iii) If MMS determines that the gross proceeds accruing to the lessee under an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between two contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of
(2) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the oil.
(c) The value of oil production from leases subject to this section which is not sold under an arm's-length contract shall be the reasonable value determined in accordance with the first applicable of the following paragraphs:
(1) The lessee's contemporaneous posted prices or oil sales contract prices used in arm's-length transactions for purchases or sales of significant quantities of like-quality oil in the same field (or, if necessary to obtain a reasonable sample, from the same area); provided, however, that those posted prices or oil sales contract prices are comparable to other contemporaneous posted prices or oil sales contract prices used in arm's-length transactions for purchases or sales of significant quantities of like-quality oil in the same field (or, if necessary to obtain a reasonable sample, from the same area). In evaluating the comparability of posted prices or oil sales contract prices, the following factors shall be considered: Price, duration, market or markets served, terms, quality of oil, volume, and other factors as may be appropriate to reflect the value of the oil. If the lessee makes arm's-length purchases or sales at different postings or prices, then the volume-weighted average price for the purchases or sales for the production month will be used;
(2) The arithmetic average of contemporaneous posted prices used in arm's-length transactions by persons other than the lessee for purchases or sales of significant quantities of like-quality oil in the same field (or, if necessary to obtain a reasonable sample, from the same area);
(3) The arithmetic average of other contemporaneous arm's-length contract prices for purchases or sales of significant quantities of like-quality oil in the same area or nearby areas;
(4) Prices received for arm's-length spot sales of significant quantities of like-quality oil from the same field (or, if necessary to obtain a reasonable sample, from the same area), and other relevant matters, including information submitted by the lessee concerning circumstances unique to a particular lease operation or the salability of certain types of oil;
(5) A net-back method or any other reasonable method to determine value;
(6) For purposes of this paragraph, the term lessee includes the lessee's designated purchasing agent, and the term contemporaneous means postings or contract prices in effect at the time the royalty obligation is incurred.
(d) Any Indian lessee will make available, upon request to the authorized MMS or Indian representatives, to the Office of the Inspector General of the Department of the Interior, or other persons authorized to receive such information, arm's-length sales and volume data for like-quality production sold, purchased, or otherwise obtained by the lessee from the field or area or from nearby fields or areas.
(e)(1) Where the value is determined under paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) A lessee shall notify MMS if it has determined value under paragraph (c)(4) or (c)(5) of this section. The notification shall be by letter to MMS Associate Director for Royalty Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following
(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest on the difference computed under 30 CFR 218.54. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method and may use that value for royalty payment purposes until MMS issues a value determination. The lessee shall submit all available data relevant to its proposal. MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination, MMS may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production, for royalty purposes, be less than the gross proceeds accruing to the lessee for lease production, less applicable allowances determined under this subpart.
(i) The lessee is required to place oil in marketable condition at no cost to the Indian lessor unless otherwise provided in the lease agreement or this section. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the oil in marketable condition.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of oil.
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Indian Tribes or allottees until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation proposals, including transportation allowances or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable laws and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. Nothing in this section is intended to limit or diminish in any manner whatsoever the right of an Indian lessor to obtain any and all information to which such lessor may be
(a)(1) Royalties shall be computed on the quantity and quality of oil as measured at the point of settlement approved by BLM for onshore leases.
(2) If the value of oil determined under § 206.52 of this subpart is based upon a quantity and/or quality different from the quantity and/or quality at the point of royalty settlement approved by the BLM for onshore leases, the value shall be adjusted for those differences in quantity and/or quality.
(b) No deductions may be made from the royalty volume or royalty value for actual or theoretical losses. Any actual loss that may be sustained prior to the royalty settlement metering or measurement point will not be subject to royalty provided that such actual loss is determined to have been unavoidable by BLM.
(c) Except as provided in paragraph (b) of this section, royalties are due on 100 percent of the volume measured at the approved point of royalty settlement. There can be no reduction in that measured volume for actual losses beyond the approved point of royalty settlement or for theoretical losses that are claimed to have taken place either prior to or beyond the approved point of royalty settlement. Royalties are due on 100 percent of the value of the oil as provided in this subpart. There can be no deduction from the value of the oil for royalty purposes to compensate for actual losses beyond the approved point of royalty settlement or for theoretical losses that are claimed to have taken place either prior to or beyond the approved point of royalty settlement.
(a) Where the value of oil has been determined under Section 206.52 of this subpart at a point (e.g., sales point or point of value determination) off the lease, MMS shall allow a deduction for the reasonable, actual costs incurred by the lessee to transport oil to a point off the lease; provided, however, that no transportation allowance will be granted for transporting oil taken as Royalty-In-Kind (RIK); or
(b)(1) Except as provided in paragraph (b)(2) of this section, the transportation allowance deduction on the basis of a selling arrangement shall not exceed 50 percent of the value of the oil at the point of sale as determined under § 206.52 of this subpart. Transportation costs cannot be transferred between selling arrangements or to other products.
(2) Upon request of a lessee, MMS may approve a transportation allowance deduction in excess of the limitation prescribed by paragraph (b)(1) of this section. The lessee must demonstrate that the transportation costs incurred in excess of the limitation prescribed in paragraph (b)(1) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) shall contain all relevant and supporting documentation necessary for MMS to make a determination. Under no circumstances shall the value, for royalty purposes, under any selling arrangement, be reduced to zero.
(c) Transportation costs must be allocated among all products produced and transported as provided in § 206.55. Transportation allowances for oil shall be expressed as dollars per barrel.
(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this subpart, then the lessee shall pay any additional royalties, plus interest determined in accordance with 30 CFR 218.54, or shall be entitled to a credit, without interest.
(a)
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration, then MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then the total transportation costs shall be allocated in a consistent and equitable manner to each of the liquid products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value). Except as provided in this paragraph, no allowance may be taken for the costs of transporting lease production which is not royalty-bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.
(3) If an arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use the oil transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all available data to support its proposal. The initial proposal must be submitted by June 30, 1988 or within 3 months after the last day of the month for which the lessee requests a transportation allowance, whichever is later (unless MMS approves a longer period). MMS shall then determine the oil transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary.
(4) Where the lessee's payments for transportation under an arm's-length contract are not on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(5) Where an arm's-length sales contract price, or a posted price, includes a provision whereby the listed price is reduced by a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. The transportation factor may be used in determining the lessee's gross proceeds for the sale of the product. The transportation factor may not
(b)
(2) The transportation allowance for non-arms-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial capital investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services or on a unit-of-production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) MMS shall allow as a cost an amount equal to the initial capital investment in the transportation system multiplied by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service after March 1, 1988.
(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and shall be effective
(3)(i) The deduction for transportation costs shall be determined on the basis of the lessee's cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, allocation of costs to each of the liquid products transported shall be in the same proportion as the ratio of the volume of each liquid product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value) and such allocation shall be made in a consistent and equitable manner. Except as provided in this paragraph, the lessee may not take an allowance for transporting lease production which is not royalty-bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.
(4) Where both gaseous and liquid products are transported through the same transportation system, the lessee shall propose a cost allocation procedure to MMS. The lessee may use the oil transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all available data to support its proposal. The initial proposal must be submitted by June 30, 1988 or within 3 months after the last day of the month for which the lessee requests a transportation allowance, whichever is later (unless MMS approves a longer period). MMS shall then determine the oil transportation allowance on the basis of the lessee's proposal and any additional information MMS deems necessary.
(5) A lessee may apply to MMS for an exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) through (b)(4) of this section. MMS will grant the exception only if the lessee has a tariff for the transportation system approved by the Federal Energy Regulatory Commission (FERC) for Indian leases. MMS shall deny the exception request if it determines that the tariff is excessive as compared to arm's-length transportation charges by pipelines, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:
(i) No FERC cost analysis exists and the FERC has declined to investigate under MMS timely objections upon filing; and
(ii) the tariff significantly exceeds the lessee's actual costs for transportation as determined under this section.
(c)
(ii) The initial Form MMS-4110 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4110 (and Schedule 1) within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during
(iv) MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(v) Transportation allowances which are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.
(2)
(ii) The initial Form MMS-4110 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until transportation under the non-arm's-length contract or the no-contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4110 containing the actual costs for the previous reporting period. If oil transportation is continuing, the lessee shall include on Form MMS-4110 its estimated costs for the next calendar year. The estimated oil transportation allowance shall be based on the actual costs for the previous reporting period plus or minus any adjustments which are based on the lessee's knowledge of decreases or increases that will affect the allowance. MMS must receive the Form MMS-4110 within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the lessee's initial Form MMS-4110 shall include estimates of the allowable oil transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.
(v) Non-arm's-length contract or no-contract transportation allowances which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used to prepare its Form MMS-4110. The data shall be provided within a reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.
(viii) If the lessee is authorized to use its FERC-approved tariff as its transportation cost in accordance with paragraph (b)(5) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(3) MMS may establish reporting dates for individual lessees different from those specified in this subpart in order to provide more effective administration. Lessees will be notified of any change in their reporting period.
(4) Transportation allowances must be reported as a separate line item on Form MMS-2014, unless MMS approves a different reporting procedure.
(d)
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.
(e)
(2) For lessees transporting production from Indian leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(f)
(g)
(a) This subpart applies to all oil produced from Federal oil and gas leases onshore and on the Outer Continental Shelf (OCS). It explains how you as a lessee must calculate the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms.
(b) If you are a designee and if you dispose of production on behalf of a lessee, the terms “you” and “your” in this subpart refer to you and not to the lessee. In this circumstance, you must determine and report royalty value for the lessee's oil by applying the rules in this subpart to your disposition of the lessee's oil.
(c) If you are a designee and only report for a lessee, and do not dispose of the lessee's production, references to “you” and “your” in this subpart refer to the lessee and not the designee. In this circumstance, you as a designee must determine and report royalty value for the lessee's oil by applying the rules in this subpart to the lessee's disposition of its oil.
(d) If the regulations in this subpart are inconsistent with:
(1) A Federal statute;
(2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation;
(3) A written agreement between the lessee and the MMS Director establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under this subpart; or
(4) An express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease provision
(e) MMS may audit and adjust all royalty payments.
The following definitions apply to this subpart:
(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.
(2) If there is ownership or common ownership of between 10 and 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:
(i) The extent to which there are common officers or directors;
(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;
(iii) Operation of a lease, plant, or other facility;
(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, or other facility; and
(v) Other evidence of power to exercise control over or common control with another person.
(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.
(1) Payments for services such as dehydration, marketing, measurement, or gathering which the lessee must perform at no cost to the Federal Government;
(2) The value of services, such as salt water disposal, that the producer normally performs but that the buyer performs on the producer's behalf;
(3) Reimbursements for harboring or terminaling fees;
(4) Tax reimbursements, even though the Federal royalty interest may be exempt from taxation;
(5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods, by allocating such payments over the production whose price the payment reduces and including the allocated amounts as proceeds for the production as it occurs; and
(6) Monies and all other consideration to which a seller is contractually or legally entitled, but does not seek to collect through reasonable efforts.
(1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights such as the right to buy back similar quantities of oil from the buyer elsewhere;
(2) The buyer pays money or other consideration for the oil; and
(3) The parties' intent is for a sale of the oil to occur.
(1) A seller agrees to sell to a buyer a specified amount of oil at a specified price over a specified period of short duration;
(2) No cancellation notice is required to terminate the sales agreement; and
(3) There is no obligation or implied intent to continue to sell in subsequent periods.
(a) The value of oil under this section is the gross proceeds accruing to the seller under the arm's-length contract, less applicable allowances determined under §§ 206.110 or 206.111. This value does not apply if you exercise an option to use a different value provided in paragraph (d)(1) or (d)(2)(i) of this section, or if one of the exceptions in paragraph (c) of this section applies. Use this paragraph (a) to value oil that:
(1) You sell under an arm's-length sales contract; or
(2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract, unless you exercise the option provided in paragraph (d)(2)(i) of this section.
(b) If you have multiple arm's-length contracts to sell oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the volume-weighted average of the values established under this section for each contract for the sale of oil produced from that lease.
(c) This paragraph contains exceptions to the valuation rule in paragraph (a) of this section. Apply these exceptions on an individual contract basis.
(1) In conducting reviews and audits, if MMS determines that any arm's-length sales contract does not reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller, MMS may require that you value the oil sold under that contract either under § 206.103 or at the total consideration received.
(2) You must value the oil under § 206.103 if MMS determines that the value under paragraph (a) of this section does not reflect the reasonable value of the production due to either:
(i) Misconduct by or between the parties to the arm's-length contract; or
(ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.
(A) MMS will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm's-length sales contract.
(B) The fact that the price received by the seller under an arm's length contract is less than other measures of market price, such as index prices, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil from the lease.
(d)(1) If you enter into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, and following the exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you may use either § 206.102(a) or § 206.103 to value your production for royalty purposes.
(i) If you use § 206.102(a), your gross proceeds are the gross proceeds under your or your affiliate's arm's-length sales contract after the exchange(s) occur(s). You must adjust your gross proceeds for any location or quality differential, or other adjustments, you received or paid under the arm's-length exchange agreement(s). If MMS determines that any arm's-length exchange agreement does not reflect reasonable location or quality differentials, MMS may require you to value the oil under § 206.103. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.
(ii) When you elect under § 206.102(d)(1) to use § 206.102(a) or § 206.103, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) sold under arm's-length contracts following arm's-length exchange agreements. You may not change your election more often than once every 2 years.
(2)(i) If you sell or transfer your oil production to your affiliate and that affiliate or another affiliate then sells the oil under an arm's-length contract, you may use either § 206.102(a) or § 206.103 to value your production for royalty purposes.
(ii) When you elect under § 206.102(d)(2)(i) to use § 206.102(a) or § 206.103, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) that your affiliates resell at arm's length. You may not change your election more often than once every 2 years.
(e) If you value oil under paragraph (a) of this section:
(1) MMS may require you to certify that your or your affiliate's arm's-length contract provisions include all of the consideration the buyer must pay, either directly or indirectly, for the oil.
(2) You must base value on the highest price the seller can receive through legally enforceable claims under the contract.
(i) If the seller fails to take proper or timely action to receive prices or benefits it is entitled to, you must pay royalty at a value based upon that obtainable price or benefit. But you will owe no additional royalties unless or until the seller receives monies or consideration resulting from the price increase or additional benefits, if:
(A) The seller makes timely application for a price increase or benefit allowed under the contract;
(B) The purchaser refuses to comply; and
(C) The seller takes reasonable documented measures to force purchaser compliance.
(ii) Paragraph (e)(2)(i) of this section will not permit you to avoid your royalty payment obligation where a purchaser fails to pay, pays only in part, or pays late. Any contract revisions or amendments that reduce prices or benefits to which the seller is entitled must be in writing and signed by all parties to the arm's-length contract.
This section explains how to value oil that you may not value under § 206.102 or that you elect under § 206.102(d) to value under this section. First determine whether paragraph (a), (b), or (c) of this section applies to production from your lease, or whether you may apply paragraph (d) or (e) with MMS approval.
(a)
(1) To calculate the daily mean spot price, average the daily high and low prices for the month in the selected publication.
(2) Use only the days and corresponding spot prices for which such prices are published.
(3) You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under § 206.112.
(4) After you select an MMS-approved publication, you may not select a different publication more often than once every 2 years, unless the publication you use is no longer published or MMS revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period.
(b)
(1) If you have an MMS-approved tendering program, value your oil under paragraph (b)(2) of this section. If you do not have an MMS-approved tendering program, you may value your oil under either paragraph (b)(3) or paragraph (b)(4) of this section.
(i) You must apply the same subparagraph of this section to value all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) that you cannot value under § 206.102 or that you elect under § 206.102(d) to value under this section.
(ii) After you select either paragraph (b)(3) or (b)(4) of this section, you may not change to the other method more often than once every 2 years, unless the method you have been using is no longer applicable and you must apply one of the other paragraphs. If you change methods, you must begin a new 2-year period.
(2) If you have an MMS-approved tendering program, the value of production from leases in the area the tendering program covers is the highest winning bid price for tendered volumes.
(i) You must offer and sell at least 30 percent of your production from both Federal and non-Federal leases in that area under your tendering program.
(ii) You also must receive at least three bids for the tendered volumes from bidders who do not have their own tendering programs that cover some or all of the same area.
(iii) MMS will provide additional criteria for approval of a tendering program in its “Oil and Gas Payor Handbook.”
(3) Value is the volume-weighted average gross proceeds accruing to the seller under your and your affiliates' arm's-length contracts for the purchase or sale of production from the field or area during the production month. The total volume purchased or sold under those contracts must exceed
(4) Value is the average of the daily mean spot prices published in any MMS-approved publication for WTI crude at Cushing, Oklahoma, during the trading month most concurrent with the production month. (For example, if the production month is June and the trading month is May 26—June 25, compute the average of the daily mean prices using the daily Cushing spot prices published in the MMS-approved publication for all the business days between and including May 26 and June 25.)
(i) Calculate the daily mean spot price by averaging the daily high and low prices for the period in the selected publication.
(ii) Use only the days and corresponding spot prices for which such prices are published.
(iii) You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under § 206.112.
(iv) After you select an MMS-approved publication, you may not select a different publication more often than once every 2 years, unless the publication you use is no longer published or MMS revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period.
(5) If you demonstrate to MMS's satisfaction that paragraphs (b)(2) through (b)(4) of this section result in an unreasonable value for your production as a result of circumstances regarding that production, the MMS Director may establish an alternative valuation method.
(c)
(1) Value is the average of the daily mean spot prices published in any MMS-approved publication:
(i) For the market center nearest your lease for crude oil similar in quality to that of your production (for example, at the St. James, Louisiana, market center, spot prices are published for both Light Louisiana Sweet and Eugene Island crude oils—their quality specifications differ significantly); and
(ii) During the trading month most concurrent with the production month. (For example, if the production month is June and the trading month is May 26-June 25, compute the average of the daily mean prices using the daily spot prices published in the MMS-approved publication for all the business days between and including May 26 and June 25 for the applicable market center.)
(2) Calculate the daily mean spot price by averaging the daily high and low prices for the period in the selected publication. Use only the days and corresponding spot prices for which such prices are published. You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under § 206.112.
(3) After you select an MMS-approved publication, you may not select a different publication more often than once every 2 years, unless the publication you use is no longer published or MMS revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period.
(d)
(e)
(1) Instead of valuing your production under paragraph (a), (b), or (c) of this section, you may apply to the MMS Director to establish a value representing the market at the refinery if:
(i) You transport your oil directly to your or your affiliate's refinery, or exchange your oil for oil delivered to your or your affiliate's refinery; and
(ii) You must value your oil under this section at an index price; and
(iii) You believe that use of the index price is unreasonable.
(2) You must provide adequate documentation and evidence demonstrating the market value at the refinery. That evidence may include, but is not limited to:
(i) Costs of acquiring other crude oil at or for the refinery;
(ii) How adjustments for quality, location, and transportation were factored into the price paid for other oil;
(iii) Volumes acquired for and refined at the refinery; and
(iv) Any other appropriate evidence or documentation that MMS requires.
(3) If the MMS Director establishes a value representing market value at the refinery, you may not take an allowance against that value under § 206.112(b) unless it is included in the Director's approval.
(a) MMS periodically will publish in the
(1) Publications buyers and sellers frequently use;
(2) Publications frequently mentioned in purchase or sales contracts;
(3) Publications that use adequate survey techniques, including development of spot price estimates based on daily surveys of buyers and sellers of ANS and other crude oil; and (4) Publications independent from MMS, other lessors, and lessees.
(b) Any publication may petition MMS to be added to the list of acceptable publications.
(c) MMS will reference the tables you must use in the publications to determine the associated index prices.
(d) MMS may revoke its approval of a particular publication if it determines that the prices published in the publication do not accurately represent spot market values.
If you determine the value of your oil under this subpart, you must retain all data relevant to the determination of royalty value.
(a) You must be able to show:
(1) How you calculated the value you reported, including all adjustments for location, quality, and transportation, and
(2) How you complied with these rules.
(b) Recordkeeping requirements are found at part 207 of this chapter.
(c) MMS may review and audit your data, and MMS will direct you to use a different value if it determines that the reported value is inconsistent with the requirements of this subpart.
You must place oil in marketable condition and market the oil for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. If you use gross proceeds under an arm's-length contract in determining value, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the oil in marketable condition or to market the oil.
(a) You may request a value determination from MMS regarding any Federal lease oil production. Your request must:
(1) Be in writing;
(2) Identify specifically all leases involved, the record title or operating rights owners of those leases, and the designees for those leases;
(3) Completely explain all relevant facts. You must inform MMS of any changes to relevant facts that occur before we respond to your request;
(4) Include copies of all relevant documents;
(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and
(6) Suggest your proposed valuation method.
(b) MMS will reply to requests expeditiously. MMS may either:
(1) Issue a value determination signed by the Assistant Secretary, Land and Minerals Management; or
(2) Issue a value determination by MMS; or
(3) Inform you in writing that MMS will not provide a value determination. Situations in which MMS typically will not provide any value determination include, but are not limited to:
(i) Requests for guidance on hypothetical situations; and
(ii) Matters that are the subject of pending litigation or administrative appeals.
(c)(1) A value determination signed by the Assistant Secretary, Land and Minerals Management, is binding on both you and MMS until the Assistant Secretary modifies or rescinds it.
(2) After the Assistant Secretary issues a value determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay late payment interest under 30 CFR 218.54.
(3) A value determination signed by the Assistant Secretary is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.
(d) A value determination issued by MMS is binding on MMS and delegated States with respect to the specific situation addressed in the determination unless the MMS (for MMS-issued value determinations) or the Assistant Secretary modifies or rescinds it.
(1) A value determination by MMS is not an appealable decision or order under 30 CFR part 290 subpart B.
(2) If you receive an order requiring you to pay royalty on the same basis as the value determination, you may appeal that order under 30 CFR part 290 subpart B.
(e) In making a value determination, MMS or the Assistant Secretary may use any of the applicable valuation criteria in this subpart.
(f) A change in an applicable statute or regulation on which any value determination is based takes precedence over the value determination, regardless of whether the MMS or the Assistant Secretary modifies or rescinds the value determination.
(g) The MMS or the Assistant Secretary generally will not retroactively modify or rescind a value determination issued under paragraph (d) of this section, unless:
(1) There was a misstatement or omission of material facts; or
(2) The facts subsequently developed are materially different from the facts on which the guidance was based.
(h) MMS may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 206.108.
Certain information you submit to MMS regarding valuation of oil, including transportation allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, MMS will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.
(a)
(1) You value oil under § 206.102 based on gross proceeds from a sale at a point off the lease, unit, or communitized area where the oil is produced, and
(2) The movement to the sales point is not gathering.
(b)
(c)
(2) You may ask MMS to approve a transportation allowance in excess of the limitation in paragraph (c)(1) of this section. You must demonstrate that the transportation costs incurred were reasonable, actual, and necessary. Your application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination. You may never reduce the royalty value of any production to zero.
(d)
(e)
(a) If you or your affiliate incur transportation costs under an arm's-length transportation contract, you may claim a transportation allowance for the reasonable, actual costs incurred for transporting oil under that contract, except as provided in paragraphs (a)(1) and (a)(2) of this section and subject to the limitation in § 206.109(c). You must be able to demonstrate that your contract is arm's length. You do not need MMS approval before reporting a transportation allowance for costs incurred under an arm's-length transportation contract.
(1) If MMS determines that the contract reflects more than the consideration actually transferred either directly or indirectly from you or your affiliate to the transporter for the transportation, MMS may require that you calculate the transportation allowance under § 206.111.
(2) You must calculate the transportation allowance under § 206.111 if MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the reasonable value of the transportation due to either:
(i) Misconduct by or between the parties to the arm's-length contract; or
(ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.
(A) MMS will not use this provision to simply substitute its judgment of the reasonable oil transportation costs incurred by you or your affiliate under an arm's-length transportation contract.
(B) The fact that the cost you or your affiliate incur in an arm's length transaction is higher than other measures of transportation costs, such as rates paid by others in the field or area, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that you or your affiliate acted unreasonably or in bad faith in transporting oil from the lease.
(b) If your arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then you must allocate the total transportation costs to each of the liquid products transported.
(1) Your allocation must use the same proportion as the ratio of the volume of each product (excluding waste products with no value) to the volume
(2) You may not claim an allowance for the costs of transporting lease production that is not royalty-bearing.
(3) You may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS will approve the method unless it is not consistent with the purposes of the regulations in this subpart.
(c) If your arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, then you must propose an allocation procedure to MMS.
(1) You may use your proposed procedure to calculate a transportation allowance until MMS accepts or rejects your cost allocation. If MMS rejects your cost allocation, you must amend your Form MMS-2014 for the months that you used the rejected method and pay any additional royalty and interest due.
(2) You must submit your initial proposal, including all available data, within 3 months after first claiming the allocated deductions on Form MMS-2014.
(d) If your payments for transportation under an arm's-length contract are not on a dollar-per-unit basis, you must convert whatever consideration is paid to a dollar-value equivalent.
(e) If your arm's-length sales contract includes a provision reducing the contract price by a transportation factor, do not separately report the transportation factor as a transportation allowance on Form MMS-2014.
(1) You may use the transportation factor in determining your gross proceeds for the sale of the product.
(2) You must obtain MMS approval before claiming a transportation factor in excess of 50 percent of the base price of the product.
(a) If you or your affiliate have a non-arm's-length transportation contract or no contract, including those situations where you or your affiliate perform your own transportation services, calculate your transportation allowance based on your or your affiliate's reasonable, actual transportation costs using the procedures provided in this section.
(b) Base your transportation allowance for non-arm's-length or no-contract situations on your or your affiliate's actual costs for transportation during the reporting period, including:
(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;
(2) Overhead under paragraph (f) of this section;
(3) Depreciation under paragraphs (g) and (h) of this section;
(4) A return on undepreciated capital investment under paragraph (i) of this section; and
(5) Once the transportation system has been depreciated below ten percent of total capital investment, a return on ten percent of total capital investment under paragraph (j) of this section.
(c) Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(d) Allowable operating expenses include:
(i) Operations supervision and engineering;
(ii) Operations labor;
(iii) Fuel;
(iv) Utilities;
(v) Materials;
(vi) Ad valorem property taxes;
(vii) Rent;
(viii) Supplies; and
(ix) Any other directly allocable and attributable operating expense which you can document.
(e) Allowable maintenance expenses include:
(i) Maintenance of the transportation system;
(ii) Maintenance of equipment;
(iii) Maintenance labor; and
(iv) Other directly allocable and attributable maintenance expenses which you can document.
(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is
(g) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit-of-production method. After you make an election, you may not change methods without MMS approval. You may not depreciate equipment below a reasonable salvage value.
(h) This paragraph describes the basis for your depreciation schedule.
(1) If you or your affiliate own a transportation system on June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs for production after June 1, 2000, on your total capital investment in the system (including your original purchase price or construction cost and subsequent reinvestment).
(2) If you or your affiliate purchased the transportation system at arm's length before June 1, 2000, you must incorporate depreciation on the schedule based on your purchase price (and subsequent reinvestment) into your transportation allowance calculations for production after June 1, 2000, beginning at the point on the depreciation schedule corresponding to that date. You must prorate your depreciation for calendar year 2000 by claiming part-year depreciation for the period from June 1, 2000 until December 31, 2000. You may not adjust your transportation costs for production before June 1, 2000, using the depreciation schedule based on your purchase price.
(3) If you are the original owner of the transportation system on June 1, 2000, or if you purchased your transportation system before March 1, 1988, you must continue to use your existing depreciation schedule in calculating actual transportation costs for production in periods after June 1, 2000.
(4) If you or your affiliate purchase a transportation system at arm's length from the original owner after June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs on your total capital investment in the system (including your original purchase price and subsequent reinvestment). You must prorate your depreciation for the year in which you or your affiliate purchased the system to reflect the portion of that year for which you or your affiliate own the system.
(5) If you or your affiliate purchase a transportation system at arm's length after June 1, 2000, from anyone other than the original owner, you must assume the depreciation schedule of the person who owned the system on June 1, 2000.
(i)(1) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transportation allowance by the rate of return provided in paragraph (i)(2) of this section.
(2) The rate of return is the industrial bond yield index for Standard and Poor's BBB rating. Use the monthly average rate published in “Standard and Poor's Bond Guide” for the first month of the reporting period for which the allowance applies. Calculate the rate at the beginning of each subsequent transportation allowance reporting period.
(j)(1) After a transportation system has been depreciated at or below a value equal to ten percent of your total capital investment, you may continue to include in the allowance calculation a cost equal to ten percent of your total capital investment in the transportation system multiplied by a rate of return under paragraph (i)(2) of this section.
(2) You may apply this paragraph to a transportation system that before June 1, 2000, was depreciated at or below a value equal to ten percent of your total capital investment.
(k) Calculate the deduction for transportation costs based on your or your affiliate's cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, allocate costs consistently and equitably to each of the liquid products transported. Your allocation must use the same proportion as the ratio of the volume of each liquid product (excluding waste products with no value) to the
(1) You may not take an allowance for transporting lease production that is not royalty-bearing.
(2) You may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS will approve the method if it is consistent with the purposes of the regulations in this subpart.
(l)(1) Where you transport both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to MMS.
(2) You may use your proposed procedure to calculate a transportation allowance until MMS accepts or rejects your cost allocation. If MMS rejects your cost allocation, you must amend your Form MMS-2014 for the months that you used the rejected method and pay any additional royalty and interest due.
(3) You must submit your initial proposal, including all available data, within 3 months after first claiming the allocated deductions on Form MMS-2014.
When you use index pricing to calculate the value of production under § 206.103, you must adjust the index price for location and quality differentials and you may adjust it for certain transportation costs, as specified in this section.
(a) If you dispose of your production under one or more arm's-length exchange agreements, then each of the conditions in this paragraph applies.
(1) You must adjust the index price for location/quality differentials. You must determine those differentials from each of your arm's-length exchange agreements applicable to the exchanged oil.
(i) Therefore, for example, if you exchange 100 barrels of production from a given lease under two separate arm's-length exchange agreements for 60 barrels and 40 barrels respectively, separately determine the location/quality differential under each of those exchange agreements, and apply each differential to the corresponding index price.
(ii) As another example, if you produce 100 barrels and exchange that 100 barrels three successive times under arm's-length agreements to obtain oil at a final destination, total the three adjustments from those exchanges to determine the adjustment under this subparagraph. (If one of the three exchanges was not at arm's length, you must request MMS approval under paragraph (b) of this section for the location/quality adjustment for that exchange to determine the total location/quality adjustment for the three exchanges.) You also could have a combination of these examples.
(2) You may adjust the index price for actual transportation costs, determined under § 206.110 or § 206.111:
(i) From the lease to the first point where you give your oil in exchange; and
(ii) From any intermediate point where you receive oil in exchange to another intermediate point where you give the oil in exchange again; and
(iii) From the point where you receive oil in exchange and transport it without further exchange to a market center, or to a refinery that is not at a market center.
(b) For non-arm's-length exchange agreements, you must request approval from MMS for any location/quality adjustment.
(c) If you transport lease production directly to a market center or to an alternate disposal point (for example, your refinery), you may adjust the index price for your actual transportation costs, determined under § 206.110 or § 206.111.
(d) If you adjust for location/quality or transportation costs under paragraphs (a), (b), or (c) of this section, also adjust the index price for quality based on premia or penalties determined by pipeline quality bank specifications at intermediate commingling points or at the market center. Make this adjustment only if and to the extent that such adjustments were not already included in the location/quality differentials determined from your arm's-length exchange agreements.
(e) For leases in the Rocky Mountain Region, for purposes of this section, the term “market center” means Cushing, Oklahoma, unless MMS specifies otherwise through notice published in the
(f) If you cannot determine your location/quality adjustment under paragraph (a) or (c) of this section, you must request approval from MMS for any location/quality adjustment.
(g) You may not use any transportation or quality adjustment that duplicates all or part of any other adjustment that you use under this section.
MMS periodically will publish in the
(a) Points where MMS-approved publications publish prices useful for index purposes;
(b) Markets served;
(c) Input from industry and others knowledgeable in crude oil marketing and transportation;
(d) Simplification; and
(e) Other relevant matters.
You or your affiliate must use a separate entry on Form MMS-2014 to notify MMS of an allowance based on transportation costs you or your affiliate incur. MMS may require you or your affiliate to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 207 of this chapter.
(a) You or your affiliate must use a separate entry on Form MMS-2014 to notify MMS of an allowance based on transportation costs you or your affiliate incur.
(b) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable oil transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems. Section 206.117 will apply when you amend your report based on your actual costs.
(c) MMS may require you or your affiliate to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 207 of this chapter.
(a) If you or your affiliate net a transportation allowance rather than report it as a separate entry against the royalty value on Form MMS-2014, you will be assessed an amount up to 10 percent of the netted allowance, not to exceed $250 per lease selling arrangement per sales period.
(b) If you or your affiliate deduct a transportation allowance on Form MMS-2014 that exceeds 50 percent of the value of the oil transported without obtaining MMS's prior approval under § 206.109, you must pay interest on the excess allowance amount taken from the date that amount is taken to the date you or your affiliate file an exception request that MMS approves. If you do not file an exception request, or if MMS does not approve your request, you must pay interest on the excess allowance amount taken from the date that amount is taken until the date you pay the additional royalties owed.
(a) If your or your affiliate's actual transportation allowance is less than the amount you claimed on Form MMS-2014 for each month during the allowance reporting period, you must pay additional royalties plus interest computed under 30 CFR 218.54 from the
(b) If the actual transportation allowance is greater than the amount you claimed on Form MMS-2014 for any month during the allowance form reporting period, you are entitled to a credit plus interest under applicable rules.
You are allowed a deduction for oil transportation which results from payments that you make (either volumetric or for value) for actual or theoretical losses only under an arm's-length contract. You may not take such a deduction under a non-arm's-length contract.
(a) Compute royalties based on the quantity and quality of oil as measured at the point of settlement approved by BLM for onshore leases or MMS for offshore leases.
(b) If the value of oil determined under this subpart is based upon a quantity or quality different from the quantity or quality at the point of royalty settlement approved by the BLM for onshore leases or MMS for offshore leases, adjust the value for those differences in quantity or quality.
(c) You may not claim a deduction from the royalty volume or royalty value for actual or theoretical losses except as provided in § 206.118. Any actual loss that you may incur before the royalty settlement metering or measurement point is not subject to royalty if BLM or MMS, as appropriate, determines that the loss is unavoidable.
(d) Except as provided in paragraph (b) of this section, royalties are due on 100 percent of the volume measured at the approved point of royalty settlement. You may not claim a reduction in that measured volume for actual losses beyond the approved point of royalty settlement or for theoretical losses that are claimed to have taken place either before or after the approved point of royalty settlement.
MMS may use an operating allowance for the purpose of computing payment obligations when specified in the notice of sale and the lease. MMS will specify the allowance amount or formula in the notice of sale and in the lease agreement.
You may adjust royalties reported and paid for the three production months beginning June 1, 2000, without liability for late payment interest. This section applies only if the adjustment results from systems changes needed to comply with new requirements imposed under this subpart that were not requirements under the predecessor rule.
(a) This subpart is applicable to all gas production from Federal oil and gas leases. The purpose of this subpart is to establish the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws and lease terms.
(b) If the specific provisions of any statute or settlement agreement between the United States and a lessee resulting from administrative or judicial litigation, or oil and gas lease subject to the requirements of this subpart are inconsistent with any regulation in this subpart, then the lease, statute, or settlement agreement shall govern to the extent of that inconsistency.
(c) All royalty payments made to MMS are subject to audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the administration of oil and gas leases is discharged in accordance with the requirements of the governing mineral leasing laws and lease terms.
For purposes of this subpart:
(a) Ownership in excess of 50 percent constitutes control;
(b) Ownership of 10 through 50 percent creates a presumption of control; and
(c) Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates.
(a)(1) This section applies to the valuation of all gas that is not processed and all gas that is processed but is sold or otherwise disposed of by the lessee pursuant to an arm's-length contract prior to processing (including all gas where the lessee's arm's-length contract for the sale of that gas prior to processing provides for the value to be determined on the basis of a percentage of the purchaser's proceeds resulting from processing the gas). This section also applies to processed gas that must be valued prior to processing in accordance with § 206.155 of this part. Where the lessee's contract includes a reservation of the right to process the gas and the lessee exercises that right, § 206.153 of this part shall apply instead of this section.
(2) The value of production, for royalty purposes, of gas subject to this subpart shall be the value of gas determined under this section less applicable allowances.
(b)(1)(i) The value of gas sold under an arm's-length contract is the gross proceeds accruing to the lessee except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit. For purposes of this section, gas which is sold or otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate pursuant to an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate. Also, where the lessee's arm's-length contract for the sale of gas prior to processing provides for the value to be determined based upon a percentage of the purchaser's proceeds resulting from processing the gas, the value of production, for royalty purposes, shall never be less than a value equivalent to 100 percent of the value of the residue gas attributable to the processing of the lessee's gas.
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or
(iii) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the gas production be valued pursuant to paragraph (c)(2) or (c)(3) of this section, and in accordance with the notification requirements of paragraph (e) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's value.
(iv)
(2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of gas sold pursuant to a warranty contract shall be determined by MMS, and due consideration will be given to all valuation criteria specified in this section. The lessee must request a value determination in accordance with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that any value determination for a warranty contract in effect on the effective date of these regulations shall remain in effect until modified by MMS.
(3) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the gas.
(c) The value of gas subject to this section which is not sold pursuant to an arm's-length contract shall be the reasonable value determined in accordance with the first applicable of the following methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like-quality gas in the same field (or, if necessary to obtain a reasonable sample, from the same area). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of gas, volume, and such other factors as may be appropriate to reflect the value of the gas;
(2) A value determined by consideration of other information relevant in valuing like-quality gas, including gross proceeds under arm's-length contracts for like-quality gas in the same field or nearby fields or areas, posted prices for gas, prices received in arm's-length spot sales of gas, other reliable public sources of price or market information, and other information as to the particular lease operation or the saleability of the gas; or
(3) A net-back method or any other reasonable method to determine value.
(d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the maximum price permitted by Federal law at which gas may be sold is less than the value determined pursuant to this section, then MMS shall accept such
(2) The limitation prescribed in paragraph (d)(1) of this section shall not apply to gas sold pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Office of the Inspector General of the Department of the Interior, or other person authorized to receive such information, arm's-length sales and volume data for like-quality production sold, purchased or otherwise obtained by the lessee from the field or area or from nearby fields or areas.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraph (c)(2) or (c)(3) of this section. The notification shall be by letter to the MMS Associate Director for Royalty Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c)(2) or (c)(3) of this section, and each time there is a change in a method under paragraph (c)(2) or (c)(3) of this section.
(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest on that difference computed pursuant to 30 CFR 218.54. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination MMS may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for lease production, less applicable allowances.
(i) The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the gas in marketable condition or to market the gas.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. If there is no contract revision or amendment, and the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract. If the lessee makes timely application for a price
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation proposals, including transportation or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. § 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this subpart are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.
(a)(1) This section applies to the valuation of all gas that is processed by the lessee and any other gas production to which this subpart applies and that is not subject to the valuation provisions of § 206.152 of this part. This section applies where the lessee's contract includes a reservation of the right to process the gas and the lessee exercises that right.
(2) The value of production, for royalty purposes, of gas subject to this section shall be the combined value of the residue gas and all gas plant products determined pursuant to this section, plus the value of any condensate recovered downstream of the point of royalty settlement without resorting to processing determined pursuant to § 206.102 of this part, less applicable transportation allowances and processing allowances determined pursuant to this subpart.
(b)(1)(i) The value of residue gas or any gas plant product sold under an arm's-length contract is the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value that the lessee reports for royalty purposes is subject to monitoring, review, and audit. For purposes of this section, residue gas or any gas plant product which is sold or otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate pursuant to an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate.
(ii) In conducting these reviews and audits, MMS will examine whether or not the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the residue gas or gas plant product. If the contract does not reflect the total consideration, then the MMS may require that the residue gas or gas plant product sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration.
(iii) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the residue gas or gas plant product because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the residue gas or gas plant product be valued pursuant to paragraph (c)(2) or (c)(3) of this section, and in accordance with the notification requirements of
(iv)
(2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of residue gas sold pursuant to a warranty contract shall be determined by MMS, and due consideration will be given to all valuation criteria specified in this section. The lessee must request a value determination in accordance with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that any value determination for a warranty contract in effect on the effective date of these regulations shall remain in effect until modified by MMS.
(3) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the residue gas or gas plant product.
(c) The value of residue gas or any gas plant product which is not sold pursuant to an arm's-length contract shall be the reasonable value determined in accordance with the first applicable of the following methods:
(1) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like quality residue gas or gas plant products from the same processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of residue gas or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the residue gas or gas plant products;
(2) A value determined by consideration of other information relevant in valuing like-quality residue gas or gas plant products, including gross proceeds under arm's-length contracts for like-quality residue gas or gas plant products from the same gas plant or other nearby processing plants, posted prices for residue gas or gas plant products, prices received in spot sales of residue gas or gas plant products, other reliable public sources of price or market information, and other information as to the particular lease operation or the saleability of such residue gas or gas plant products; or
(3) A net-back method or any other reasonable method to determine value.
(d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the maximum price permitted by Federal law at which any residue gas or gas plant products may be sold is less than the value determined pursuant to this section, then MMS shall accept such maximum price as the value. For the purposes of this section, price limitations set by any State or local government shall not be considered as a maximum price permitted by Federal law.
(2) The limitation prescribed by paragraph (d)(1) of this section shall not apply to residue gas sold pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section.
(e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject
(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Office of the Inspector General of the Department of the Interior, or other persons authorized to receive such information, arm's-length sales and volume data for like-quality residue gas and gas plant products sold, purchased or otherwise obtained by the lessee from the same processing plant or from nearby processing plants.
(3) A lessee shall notify MMS if it has determined any value pursuant to paragraph (c)(2) or (c)(3) of this section. The notification shall be by letter to the MMS Associate Director for Royalty Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c)(2) or (c)(3) of this section, and each time there is a change in a method under paragraph (c)(2) or (c)(3) of this section.
(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest computed on that difference pursuant to 30 CFR 218.54. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination, MMS may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for residue gas and/or any gas plant products, less applicable transportation allowances and processing allowances determined pursuant to this subpart.
(i) The lessee must place residue gas and gas plant products in marketable condition and market the residue gas and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the residue gas or gas plant products in marketable condition or to market the residue gas and gas plant products.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding against the Federal Government or its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support valuation proposals, including transportation allowances, processing allowances or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.
(a)(1) Royalties shall be computed on the basis of the quantity and quality of unprocessed gas at the point of royalty settlement approved by BLM or MMS for onshore and OCS leases, respectively.
(2) If the value of gas determined pursuant to § 206.152 of this subpart is based upon a quantity and/or quality that is different from the quantity and/or quality at the point of royalty settlement, as approved by BLM or MMS, that value shall be adjusted for the differences in quantity and/or quality.
(b)(1) For residue gas and gas plant products, the quantity basis for computing royalties due is the monthly net output of the plant even though residue gas and/or gas plant products may be in temporary storage.
(2) If the value of residue gas and/or gas plant products determined pursuant to § 206.153 of this subpart is based upon a quantity and/or quality of residue gas and/or gas plant products that is different from that which is attributable to a lease, determined in accordance with paragraph (c) of this section, that value shall be adjusted for the differences in quantity and/or quality.
(c) The quantity of the residue gas and gas plant products attributable to a lease shall be determined according to the following procedure:
(1) When the net output of the processing plant is derived from gas obtained from only one lease, the quantity of the residue gas and gas plant products on which computations of royalty are based is the net output of the plant.
(2) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to each lease shall be in the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of nonuniform content, the quantity of the residue gas allocable to each lease will be determined by multiplying the amount of gas delivered to the plant from the lease by the residue gas content of the gas, and dividing the arithmetical product thus obtained by the sum of the similar arithmetical products separately obtained for all leases from which gas is delivered to the plant, and then multiplying the net output of the residue gas by the arithmetic quotient obtained. The net output of gas plant products allocable to each lease will be determined by multiplying the amount of gas delivered to the plant from the lease by the gas plant product content of the gas, and dividing the arithmetical product thus
(4) A lessee may request MMS approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If approved, such method will be applicable to all gas production from Federal leases that is processed in the same plant.
(d)(1) No deductions may be made from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas that may be sustained prior to the royalty settlement metering or measurement point will not be subject to royalty provided that such loss is determined to have been unavoidable by BLM or MMS, as appropriate.
(2) Except as provided in paragraph (d)(1) of this section and 30 CFR 202.151(c), royalties are due on 100 percent of the volume determined in accordance with paragraphs (a) through (c) of this section. There can be no reduction in that determined volume for actual losses after the quantity basis has been determined or for theoretical losses that are claimed to have taken place. Royalties are due on 100 percent of the value of the unprocessed gas, residue gas, and/or gas plant products as provided in this subpart, less applicable allowances. There can be no deduction from the value of the unprocessed gas, residue gas, and/or gas plant products to compensate for actual losses after the quantity basis has been determined, or for theoretical losses that are claimed to have taken place.
(a) Except as provided in paragraph (b) of this section, where the lessee (or a person to whom the lessee has transferred gas pursuant to a non-arm's-length contract or without a contract) processes the lessee's gas and after processing the gas the residue gas is not sold pursuant to an arm's-length contract, the value, for royalty purposes, shall be the greater of (1) the combined value, for royalty purposes, of the residue gas and gas plant products resulting from processing the gas determined pursuant to § 206.153 of this subpart, plus the value, for royalty purposes, of any condensate recovered downstream of the point of royalty settlement without resorting to processing determined pursuant to § 206.102 of this subpart; or (2) the value, for royalty purposes, of the gas prior to processing determined in accordance with § 206.152 of this subpart.
(b) The requirement for accounting for comparison contained in the terms of leases will govern as provided in § 206.150(b) of this subpart. When accounting for comparison is required by the lease terms, such accounting for comparison shall be determined in accordance with paragraph (a) of this section.
(a) Where the value of gas has been determined pursuant to § 206.152 or § 206.153 of this subpart at a point (e.g., sales point or point of value determination) off the lease, MMS shall allow a deduction for the reasonable actual costs incurred by the lessee to transport unprocessed gas, residue gas, and gas plant products from a lease to a point off the lease including, if appropriate, transportation from the lease to a gas processing plant off the lease and from the plant to a point away from the plant.
(b) Transportation costs must be allocated among all products produced and transported as provided in § 206.157.
(c)(1) Except as provided in paragraph (c)(3) of this section, for unprocessed gas valued in accordance with § 206.152 of this subpart, the transportation allowance deduction on the basis of a selling arrangement shall not exceed 50 percent of the value of the unprocessed gas determined in accordance with § 206.152 of this subpart.
(2) Except as provided in paragraph (c)(3) of this section, for gas production valued in accordance with § 206.153 of this subpart the transportation allowance deduction on the basis of a selling
(3) Upon request of a lessee, MMS may approve a transportation allowance deduction in excess of the limitations prescribed by paragraphs (c)(1) and (c)(2) of this section. The lessee must demonstrate that the transportation costs incurred in excess of the limitations prescribed in paragraphs (c)(1) and (c)(2) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) shall contain all relevant and supporting documentation necessary for MMS to make a determination. Under no circumstances shall the value for royalty purposes under any selling arrangement be reduced to zero.
(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this subpart, then the lessee shall pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.54, or shall be entitled to a credit, without interest. If the lessee takes a deduction for transportation on the Form MMS-2014 by improperly netting the allowance against the sales value of the unprocessed gas, residue gas, and gas plant products instead of reporting the allowance as a separate line item, he may be assessed an additional amount under 206.157(d).
(a)
(ii) In conducting reviews and audits, MMS will examine whether or not the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration, then the MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.
(iii) If the MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(2)(i) If an arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract, the total transportation costs shall be allocated in a consistent and equitable manner to each of the products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, no allowance may be taken for the costs of transporting
(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.
(3) If an arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use the transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. MMS shall then determine the gas transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on the Form MMS-2014.
(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar per unit, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(5) Where an arm's-length sales contract price or a posted price includes a provision whereby the listed price is reduced by a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. The transportation factor may be used in determining the lessee's gross proceeds for the sale of the product. The transportation factor may not exceed 50 percent of the base price of the product without MMS approval.
(b)
(2) The transportation allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee has elected to use either method for a transportation system, the lessee may not later
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable initial capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service after March 1, 1988.
(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3)(i) The deduction for transportation costs shall be determined on the basis of the lessee's cost of transporting each product through each individual transportation system. Where more than one product in a gaseous phase is transported, the allocation of costs to each of the products transported shall be made in a consistent and equitable manner in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, the lessee may not take an allowance for transporting a product which is not royalty bearing without MMS approval.
(ii) Notwithstanding the requirements of paragraph (b)(3)(i), the lessee may propose to the MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.
(4) Where both gaseous and liquid products are transported through the same transportation system, the lessee shall propose a cost allocation procedure to MMS. The lessee may use the transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. MMS shall then determine the transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on the Form MMS-2014.
(5) A lessee may apply to the MMS for an exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) through (b)(4) of this section. The MMS will grant the exception only if the lessee has a tariff for the transportation system approved by the Federal Energy Regulatory Commission (FERC) (for both Federal and Indian leases) or a State regulatory agency (for Federal leases). The MMS shall deny the exception request if it determines that the tariff is excessive as compared to arm's-length transportation charges by pipelines, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if: (i) No FERC or State regulatory agency cost analysis exists and the FERC or State regulatory agency, as applicable, has declined to investigate pursuant to MMS timely objections upon filing; and (ii) the tariff significantly exceeds the lessee's actual costs for transportation as determined under this section.
(c)
(ii) The MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(2)
(ii) For new transportation facilities or arrangements, the lessee's initial deduction shall include estimates of the allowable gas transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.
(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use its FERC-approved or State regulatory agency-approved tariff as its transportation cost in accordance with paragraph (b)(5) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(d)
(2) If a lessee deducts a transportation allowance on its Form MMS-2014 that exceeds 50 percent of the value of the gas transported without obtaining prior approval of MMS under § 206.156, the lessee shall pay interest on the excess allowance amount taken from the date such amount is taken to the date the lessee files an exception request with MMS.
(3) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(4) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.
(e)
(2) For lessees transporting production from onshore Federal leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(3) For lessees transporting gas production from leases on the OCS, if the lessee's estimated transportation allowance exceeds the allowance based on actual costs, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with its payment, in accordance with instructions provided by MMS. If the lessee's estimated transportation allowance is less than the allowance based on actual costs, the refund procedure will be specified by MMS.
(f)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(g)
(1)
(2)
(3)
(i)
(ii)
(iii)
(iv)
(4)
(5)
(h)
(a) Where the value of gas is determined pursuant to § 206.153 of this subpart, a deduction shall be allowed for the reasonable actual costs of processing.
(b) Processing costs must be allocated among the gas plant products. A separate processing allowance must be determined for each gas plant product and processing plant relationship. Natural gas liquids (NGL's) shall be considered as one product.
(c)(1) Except as provided in paragraph (d)(2) of this section, the processing allowance shall not be applied against the value of the residue gas. Where there is no residue gas MMS may designate an appropriate gas plant product against which no allowance may be applied.
(2) Except as provided in paragraph (c)(3) of this section, the processing allowance deduction on the basis of an individual product shall not exceed 66
(3) Upon request of a lessee, MMS may approve a processing allowance in excess of the limitation prescribed by paragraph (c)(2) of this section. The lessee must demonstrate that the processing costs incurred in excess of the limitation prescribed in paragraph (c)(2) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) shall contain all relevant and supporting documentation for MMS to make a determination. Under no circumstances shall the value for royalty purposes of any gas plant product be reduced to zero.
(d)(1) Except as provided in paragraph (d)(2) of this section, no processing cost deduction shall be allowed for the costs of placing lease products in marketable condition, including dehydration, separation, compression, or storage, even if those functions are performed off the lease or at a processing plant. Where gas is processed for the removal of acid gases, commonly referred to as “sweetening,” no processing cost deduction shall be allowed for such costs unless the acid gases removed are further processed into a gas plant product. In such event, the lessee shall be eligible for a processing allowance as determined in accordance with this subpart. However, MMS will not grant any processing allowance for processing lease production which is not royalty bearing.
(2)(i) If the lessee incurs extraordinary costs for processing gas production from a gas production operation, it may apply to MMS for an allowance for those costs which shall be in addition to any other processing allowance to which the lessee is entitled pursuant to this section. Such an allowance may be granted only if the lessee can demonstrate that the costs are, by reference to standard industry conditions and practice, extraordinary, unusual, or unconventional.
(ii) Prior MMS approval to continue an extraordinary processing cost allowance is not required. However, to retain the authority to deduct the allowance the lessee must report the deduction to MMS in a form and manner prescribed by MMS.
(e) If MMS determines that a lessee has improperly determined a processing allowance authorized by this subpart, then the lessee shall pay any additional royalties, plus interest determined in accordance with 30 CFR 218.54, or shall be entitled to a credit, without interest. If the lessee takes a deduction for processing on the Form
(a)
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the processor for the processing. If the contract reflects more than the total consideration, then the MMS may require that the processing allowance be determined in accordance with paragraph (b) of this section.
(iii) If MMS determines that the consideration paid pursuant to an arm's-length processing contract does not reflect the reasonable value of the processing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and lessor, then MMS shall require that the processing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the processing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's processing costs.
(2) If an arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product can be determined from the contract, then the processing costs for each gas plant product shall be determined in accordance with the contract. No allowance may be taken for the costs of processing lease production which is not royalty-bearing.
(3) If an arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use its proposed allocation procedure until MMS issues its determination. The lessee shall submit all relevant data to support its proposal. MMS shall then determine the processing allowance based upon the lessee's proposal and any additional information MMS deems necessary. No processing allowance will be granted for the costs of processing lease production which is not royalty bearing. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on Form MMS-2014.
(4) Where the lessee's payments for processing under an arm's-length contract are not based on a dollar per unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b)
(2) The processing allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for processing during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the processing plant.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the processing plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the processing plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.
(iv) A lessee may use either depreciation or a return on depreciable capital investment. When a lessee has elected to use either method for a processing plant, the lessee may not later elect to change to the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the processing plant services, or a unit-of-production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a processing plant shall not alter the depreciation schedule established by the original processor/lessee for purposes of the allowance calculation. With or without a change in ownership, a processing plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable initial capital investment in the processing plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service after March 1, 1988.
(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3) The processing allowance for each gas plant product shall be determined based on the lessee's reasonable and actual cost of processing the gas. Allocation of costs to each gas plant product shall be based upon generally accepted accounting principles. The lessee may not take an allowance for the costs of processing lease production which is not royalty bearing.
(4) A lessee may apply to MMS for an exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) through (b)(3) of this section. The MMS may grant the exception only if: (i) The lessee has arm's-length contracts for processing other gas production at the same processing plant; and (ii) at least 50 percent of the gas processed annually at the plant is processed pursuant to arm's-length processing contracts; if the MMS grants the exception, the lessee shall use as its processing allowance the volume weighted average prices charged other persons pursuant to arm's-length contracts for processing at the same plant.
(c)
(ii) The MMS may require that a lessee submit arm's-length processing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(2)
(ii) For new processing plants, the lessee's initial deduction shall include estimates of the allowable gas processing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant or, if such data are not available, the lessee shall use estimates based upon industry data for similar gas processing plants.
(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use the volume weighted average prices charged other persons as its processing allowance in accordance with paragraph (b)(4) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(d)
(2) If a lessee deducts a processing allowance on its Form MMS-2014 that exceeds 66
(3) If a lessee erroneously reports a processing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(4) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.
(e)
(2) For lessees processing production from onshore Federal leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(3) For lessees processing gas production from leases on the OCS, if the lessee's estimated processing allowance exceeds the allowance based on actual costs, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with its payment, in accordance with instructions provided by MMS. If the lessee's estimated costs were less than the actual costs, the refund procedure will be specified by MMS.
(f)
Notwithstanding any other provisions in these regulations, an operating allowance may be used for the purpose of computing payment obligations when specified in the notice of sale and the lease. The allowance amount or
This subpart contains royalty valuation provisions applicable to Indian lessees.
(a) This subpart applies to all gas production from Indian (tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation). The purpose of this subpart is to establish the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms. This subpart does not apply to Federal leases.
(b) If the specific provisions of any Federal statute, treaty, negotiated agreement, settlement agreement resulting from any administrative or judicial proceeding, or Indian oil and gas lease are inconsistent with any regulation in this subpart, then the Federal statute, treaty, negotiated agreement, settlement agreement, or lease will govern to the extent of that inconsistency.
(c) You may calculate the value of production for royalty purposes under methods other than those the regulations in this title require, but only if you, the tribal lessor, and MMS jointly agree to the valuation methodology. For leases on Indian allotted lands, you and MMS must agree to the valuation methodology.
(d) All royalty payments you make to MMS are subject to monitoring, review, audit, and adjustment.
(e) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian oil and gas leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.
The following definitions apply to this subpart and to subpart J of part 202 of this title:
(1) Ownership in excess of 50 percent constitutes control.
(2) Ownership of 10 through 50 percent creates a presumption of control.
(3) Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any
(a)
(1) You must use the valuation provision of this section if your lease is in an index zone and meets one of the following two requirements:
(i) Has a major portion provision;
(ii) Does not have a major portion provision, but provides for the Secretary to determine the value of production.
(2) This section does not apply to carbon dioxide, nitrogen, or other non-hydrocarbon components of the gas stream. However, if they are recovered and sold separately from the gas stream, you must determine the value of these products under § 206.174.
(b)
(i) Gas production before processing;
(ii) Gas production that you certify on Form MMS-4410, Certification for Not Performing Accounting for Comparison (Dual Accounting), is not processed before it flows into a pipeline with an index but which may be processed later;
(iii) Residue gas after processing; and
(iv) Gas that is never processed.
(2) The value of gas production that is not sold under an arm's-length dedicated contract is the index-based value determined under paragraph (d) of this section unless the gas was subject to a previous contract which was part of a gas contract settlement. If the previous contract was subject to a gas
(3) The value of gas production that is sold under an arm's-length dedicated contract is the higher of the index-based value under paragraph (d) of this section or the value of that production determined under § 206.174(b).
(c)
(1) The value of the gas before processing determined under paragraph (b) of this section.
(2) The value of the gas after processing, which is either the alternative dual accounting value under § 206.173 or the sum of the following three values:
(i) The value of the residue gas determined under paragraph (b)(2) or (3) of this section, as applicable;
(ii) The value of the gas plant products determined under § 206.174, less any applicable processing and/or transportation allowances determined under this subpart; and
(iii) The value of any drip condensate associated with the processed gas determined under subpart B of this part.
(d)
(i) For each MMS-approved publication, calculate the average of the highest reported prices for all index-pricing points in the index zone, except for any prices excluded under paragraph (d)(6) of this section;
(ii) Sum the averages calculated in paragraph (d)(1)(i) of this section and divide by the number of publications; and
(iii) Reduce the number calculated under paragraph (d)(1)(ii) of this section by 10 percent, but not by less than 10 cents per MMBtu or more than 30 cents per MMBtu. The result is the index-based value per MMBtu for production from all leases in that index zone.
(2) MMS will publish in the
(i) Areas for which MMS-approved publications establish index prices that accurately reflect the value of production in the field or area where the production occurs;
(ii) Common markets served;
(iii) Common pipeline systems;
(iv) Simplification; and
(v) Easy identification in MMS's systems, such as counties or Indian reservations.
(3) If market conditions change so that an index-based method for determining value is no longer appropriate for an index zone, MMS will hold a technical conference to consider disqualification of an index zone. MMS will publish notice in the
(4) MMS periodically will publish in the
(i) Publications buyers and sellers frequently use;
(ii) Publications frequently referenced in purchase or sales contracts;
(iii) Publications that use adequate survey techniques, including the gathering of information from a substantial number of sales;
(iv) Publications that publish the range of reported prices they use to calculate their index; and
(v) Publications independent from DOI, lessors, and lessees.
(5) Any publication may petition MMS to be added to the list of acceptable publications.
(6) MMS may exclude an individual index price for an index zone in an MMS-approved publication if MMS determines that the index price does not accurately reflect the value of production in that index zone. MMS will publish a list of excluded indices in the
(7) MMS will reference which tables in the publications you must use for determining the associated index prices.
(8) The index-based values determined under this paragraph are not subject to deductions for transportation or processing allowances determined under §§ 206.177, 206.178, 206.179, and 206.180.
(e)
(2) By June 30 following any calendar year, you must calculate for each month of that calendar year your safety net price per MMBtu using the procedures in paragraph (e)(3) of this section. You must calculate a safety net price for each month and for each index zone where you have an Indian lease for which you report and pay royalties.
(3) Your safety net price (S) for an index zone is the volume-weighted average contract price per delivered MMBtu under your or your affiliate's arm's-length contracts for the disposition of residue gas or unprocessed gas produced from your Indian leases in that index zone as computed under this paragraph (e)(3).
(i) Include in your calculation only sales under those contracts that establish a delivery point beyond the first index pricing point through which the gas flows, and that include any gas produced from or allocable to one or more of your Indian leases in that index zone, even if the contract also includes gas produced from Federal, State, or fee properties. Include in your volume-weighted average calculation those volumes that are allocable to your Indian leases in that index zone.
(ii) Do not reduce the contract price for any transportation costs incurred to deliver the gas to the purchaser.
(iii) For purposes of this paragraph (e), the contract price will not include the following amounts:
(A) Any amounts you receive in compromise or settlement of a predecessor contract for that gas;
(B) Deductions for you or any other person to put gas production into marketable condition or to market the gas; and
(C) Any amounts related to marketable securities associated with the sales contract.
(4) Next, you must determine for each month the safety net differential (SND). You must perform this calculation separately for each index zone.
(i) For each index zone, the safety net differential is equal to: SND = [(0.80 × S) − (1.25 × I)] where (I) is the index-based value determined under 30 CFR 206.172(d).
(ii) If the safety net differential is positive you owe additional royalties.
(5)(i) To calculate the additional royalties you owe, make the following calculation for each of your Indian leases in that index zone that produced gas that was sold beyond the first index-pricing point through which the gas flowed and that was used in the calculation in paragraph (e)(3) of this section:
Lease royalties owed = SND × V × R, where R = the lease royalty rate and V = the volume allocable to the lease which produced gas that was sold beyond the first index pricing point.
(ii) If gas produced from any of your Indian leases is commingled or pooled with gas produced from non-Indian properties, and if any of the combined gas is sold at a delivery point beyond the first index pricing point through which the gas flows, then the volume allocable to each Indian lease for which gas was sold beyond the first index pricing point in the calculation under
(iii) Add the numbers calculated for each lease under paragraph (e)(5)(i) of this section. The total is the additional royalty you owe.
(6) You have the following responsibilities to comply with the minimum value for royalty purposes:
(i) You must report the safety net price for each index zone to MMS on Form MMS-4411, Safety Net Report, no later than June 30 following each calendar year;
(ii) You must pay and report on Form MMS-2014 additional royalties due no later than June 30 following each calendar year; and
(iii) MMS may order you to amend your safety net price within one year from the date your Form MMS-4411 is due or is filed, whichever is later. If MMS does not order any amendments within that one-year period, your safety net price calculation is final.
(f)
(i) If MMS approves the request for your lease, you must value your production under § 206.174 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the
(ii) If an Indian tribe requests exclusion from an index zone for less than all of its leases, MMS will approve the request only if the excluded leases may be segregated into one or more groups based on separate fields within the reservation.
(2) An Indian tribe may ask MMS to terminate exclusion of its leases from valuation under this section. MMS will consult with BIA regarding the request.
(i) If MMS approves the request, you must value your production under § 206.172 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the
(ii) Termination of an exclusion under paragraph (f)(2)(i) of this section cannot take effect earlier than 1 year after the first day of the production month that the exclusion was effective.
(3) The Indian tribe's request to MMS under either paragraph (f)(1) or (2) of this section must be in the form of a tribal resolution.
(g)
(ii) If MMS excludes your lease, you must value your production under § 206.174 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the
(iii) If MMS excludes any Indian allotted leases under this paragraph (g)(1), it will exclude all Indian allotted leases in the same field.
(2)(i) MMS may terminate the exclusion of any Indian allotted leases from valuation under this section. MMS will consult with BIA regarding the termination.
(ii) If MMS terminates the exclusion, you must value your production under § 206.172 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the
(a)
(2) You must make a separate election to use the alternative methodology for dual accounting for your Indian leases in each MMS-designated
(i) MMS will publish in the
(A) Alabama-Coushatta;
(B) Blackfeet Reservation;
(C) Crow Reservation;
(D) Fort Belknap Reservation;
(E) Fort Berthold Reservation;
(F) Fort Peck Reservation;
(G) Jicarilla Apache Reservation;
(H) MMS-designated groups of counties in the State of Oklahoma;
(I) Navajo Reservation;
(J) Northern Cheyenne Reservation;
(K) Rocky Boys Reservation;
(L) Southern Ute Reservation;
(M) Turtle Mountain Reservation;
(N) Ute Mountain Ute Reservation;
(O) Uintah and Ouray Reservation;
(P) Wind River Reservation; and
(Q) Any other area that MMS designates. MMS will publish a new area designation in the
(ii) You may elect to begin using the alternative methodology for dual accounting at the beginning of any month. The first election to use the alternative methodology will be effective from the time of election through the end of the following calendar year. Thereafter, each election to use the alternative methodology must remain in effect for 2 calendar years. You may return to the actual dual accounting method only at the beginning of the next election period or with the written approval of MMS and the tribal lessor for tribal leases, and MMS for Indian allottee leases in the designated area.
(iii) When you elect to use the alternative methodology for a designated area, you must also use the alternative methodology for any new wells commenced and any new leases acquired in the designated area during the term of the election.
(b)
(2) To calculate the value of the gas after processing using the alternative methodology for dual accounting, you must apply the increase to the value before processing, determined in either § 206.172 or § 206.174, as follows:
(i) Value of gas after processing = (value determined under either § 206.172 or § 206.174, as applicable) × (1 + increment for dual accounting); and
(ii) In this equation, the increment for dual accounting is the number you take from the applicable Btu range, determined under paragraph (b)(3) of this section, in the following table:
(3) The applicable Btu for purposes of this section is the volume weighted-average Btu for the lease computed from measurements at the facility measurement point(s) for gas production from the lease.
(4) If any of your gas from the lease is processed during a month, use the following two paragraphs to determine which amounts are subject to dual accounting and which dual accounting method you must use.
(i) Weighted-average Btu content determined under paragraph (b)(3) of this section is greater than 1,000 Btu's per cubic foot (Btu/cf). All gas production from the lease is subject to dual accounting and you must use the alternative method for all that gas production if you elected to use the alternative method under this section.
(ii) Weighted-average Btu content determined under paragraph (b)(3) of this section is less than or equal to 1,000 Btu/cf. Only the volumes of lease production measured at facility measurement points whose quality exceeds 1,000 Btu/cf are subject to dual accounting, and you may use the alternative methodology for these volumes. For gas measured at facility measurement points for these leases where the quality is equal to or less than 1,000 Btu/cf, you are not required to do dual accounting.
(a)
(i) Your lease is not in an index zone (or MMS has excluded your lease from an index zone).
(ii) If your lease is in an index zone and you sell your gas under an arm's-length dedicated contract, then the value of your gas is the higher of the value received under the dedicated contract determined under § 206.174(b) or the value under § 206.172.
(iii) Also use this section to value any other gas production that cannot be valued under § 206.172, as well as gas plant products, and to value components of the gas stream that have no Btu value (for example, carbon dioxide, nitrogen, etc.).
(2) The value for royalty purposes of gas production subject to this subpart is the value of gas determined under this section less applicable allowances determined under this subpart.
(3) You must determine the value of gas production that is processed and is subject to accounting for comparison using the procedure in § 206.176.
(4) This paragraph applies if your lease has a major portion provision. It also applies if your lease does not have a major portion provision but the lease provides for the Secretary to determine value.
(i) The value of production you must initially report and pay is the value determined in accordance with the other paragraphs of this section.
(ii) MMS will determine the major portion value and notify you in the
(iii) Except as provided in paragraph (a)(4)(iv) of this section, MMS will calculate the major portion value for each designated area (which are the same designated areas as under § 206.173) using values reported for unprocessed gas and residue gas on Form MMS-2014 for gas produced from leases on that Indian reservation or other designated area. MMS will array the reported prices from highest to lowest price. The major portion value is that price at which 25 percent (by volume) of the gas (starting from the highest) is sold. MMS cannot unilaterally change the major portion value after you are notified in writing of what that value is for your leases.
(iv) MMS may calculate the major portion value using different data than the data described in paragraph (a)(4)(iii) of this section or data to augment the data described in paragraph (a)(4)(iii) of this section. This may include price data reported to the State tax authority or price data from leases MMS has reviewed in the designated area. MMS may use this alternate or the augmented data source beginning with production on the first day of the month following the date MMS publishes notice in the
(b)
(i) You have the burden of demonstrating that your contract is arm's-length.
(ii) In conducting reviews and audits for gas valued based upon gross proceeds under this paragraph, MMS will examine whether or not your contract reflects the total consideration actually transferred either directly or indirectly from the buyer to you or your affiliate for the gas, residue gas, or gas plant product. If the contract does not reflect the total consideration, then MMS may require that the gas, residue gas, or gas plant product sold under that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to you or your affiliate, including the additional consideration.
(iii) If MMS determines for gas valued under this paragraph that the gross proceeds accruing to you or your affiliate under an arm's-length contract do not reflect the value of the gas, residue gas, or gas plant products because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the gas, residue gas, or gas plant product be valued under paragraphs (c)(2) or (3) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your value.
(iv) This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price specified in the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessees must value all over-delivered volumes under paragraph (c)(2) or (3) of this section.
(2) MMS may require you to certify that your arm's-length contract provisions include all of the consideration the buyer pays, either directly or indirectly, for the gas, residue gas, or gas plant product.
(c)
(1) The gross proceeds accruing to you under your non-arm's-length contract sale (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like-quality gas in the same field (or, if necessary to obtain a reasonable sample, from the same area). For residue gas or gas plant products, the comparable arm's-length contracts must be for gas from the same processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors will be considered: price, time of execution, duration, market or markets served, terms, quality of gas, residue gas, or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the gas, residue gas, or gas plant products.
(2) A value determined by consideration of other information relevant in valuing like-quality gas, residue gas, or gas plant products, including gross proceeds under arm's-length contracts for like-quality gas in the same field or nearby fields or areas, or for residue gas or gas plant products from the same gas plant or other nearby processing plants. Other factors to consider
(3) A net-back method or any other reasonable method to determine value.
(d)
(1) Such data will be subject to review and audit, and MMS will direct you to use a different value if we determine upon review or audit that the value you reported is inconsistent with the requirements of these regulations.
(2) You must make all such data available upon request to the authorized MMS or Indian representatives, to the Office of the Inspector General of the Department, or other authorized persons. This includes your arm's-length sales and volume data for like-quality gas, residue gas, and gas plant products that are sold, purchased, or otherwise obtained from the same processing plant or from nearby processing plants, or from the same or nearby field or area.
(e)
(f)
(g)
(2) For gas plant products valued under this section and not valued under § 206.173, the alternative methodology for dual accounting, the minimum value of production for each gas plant product is as follows:
(i) Leases in certain States and areas have specific minimum values.
(A) For production from leases in Colorado in the San Juan Basin, New Mexico, and Texas, the monthly average minimum price reported in commercial price bulletins for the gas plant product at Mont Belvieu, Texas, minus 8.0 cents per gallon.
(B) For production in Arizona, in Colorado outside the San Juan Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah, and Wyoming, the monthly average minimum price reported in commercial price bulletins for the gas plant product at Conway, Kansas, minus 7.0 cents per gallon;
(ii) You may use any commercial price bulletin, but you must use the same bulletin for all of the calendar year. If the commercial price bulletin you are using stops publication, you may use a different commercial price bulletin for the remaining part of the calendar year; and (iii) If you use a commercial price bulletin that is published monthly, the monthly average minimum price is the bulletin's minimum price. If you use a commercial price bulletin that is published weekly, the monthly average minimum price is the arithmetic average of the bulletin's weekly minimum prices. If you use a commercial price bulletin that is published daily, the monthly average minimum price is the arithmetic average of the bulletin's minimum prices for each Wednesday in the month.
(h)
(i)
(j)
(k)
(l)
(i) If your royalty valuation does not include a non-arm's-length allowance under this subpart, you have until the last day of the 13th month following the production month to report any adjustments on Form MMS-2014. MMS must complete royalty audits timely and may not issue demands or orders or initiate other action to collect royalty underpayment for this production from the lessee after the last day of the 12th month following the last day to make adjustments.
(ii) If your royalty valuation includes a non-arm's-length allowance under this subpart, you have until the last day of the 9th month following the month you submit to MMS your actual transportation allowance report, or your actual processing allowance report, to report any adjustments on Form MMS-2014. MMS must complete royalty audits timely and may not issue demands or orders or initiate any other action to collect royalty underpayments for this production from the lessee after the last day of the 12th month following the last day to report adjustments.
(2) Exceptions to the time limits in paragraph (l)(1) of this section are as follows:
(i) If you have a pending dispute with your purchaser or with the person
(ii) If there is a written agreement between you and MMS or its delegee (if applicable) to extend the time limit, the time period is extended for the period stated in the agreement;
(iii) If there is a pending regulatory proceeding by any agency with jurisdiction over sales prices for gas that could affect the value of the gas, the time period to make adjustments in paragraphs (l)(1)(i) and (ii) of this section will be extended for 90 days after final resolution of the pending regulatory proceeding, including any period for judicial review. The time period to complete audits and issue demands or orders is correspondingly extended;
(iv) If the lessee fails or refuses to provide records or information in its possession or control necessary to complete the audit, the time period to issue demands or orders will be extended for any time periods that MMS cannot obtain the records or information; and
(v) The time period in paragraphs (l)(1)(i) and (ii) of this section will not apply in situations involving fraud or intentional misrepresentation or concealment of a material fact for the purpose of evading a payment obligation.
(3) For purposes of this paragraph (l),
(4) If an audit discloses overpayments for any lease, the lessee may credit those overpayments against any underpayments due on that same lease.
(a) For unprocessed gas, you must pay royalties on the quantity and quality at the facility measurement point BLM either allowed or approved.
(b) For residue gas and gas plant products, you must pay royalties on your share of the monthly net output of the plant even though residue gas and/or gas plant products may be in temporary storage.
(c) If you have no ownership interest in the processing plant and you do not operate the plant, you may use the contract volume allocation to determine your share of plant products.
(d) If you have an ownership interest in the plant or if you operate it, use the following procedure to determine the quantity of the residue gas and gas plant products attributable to you for royalty payment purposes:
(1) When the net output of the processing plant is derived from gas obtained from only one lease, the quantity of the residue gas and gas plant products on which you must pay royalty is the net output of the plant.
(2) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to each lease must be in the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases.
(3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of non-uniform content, the volumes of residue gas and gas plant products allocable to each lease are based on theoretical volumes of residue gas and gas plant products measured in the lease gas stream. You must calculate the portion of net plant output of residue gas and gas plant products attributable to each lease as follows:
(i) First, compute the theoretical volumes of residue gas and of gas plant products attributable to the lease by multiplying the lease volume of the gas stream by the tested residue gas content (mole percentage) or gas plant
(ii) Second, calculate the theoretical volumes of residue gas and of gas plant products delivered from all leases by summing the theoretical volumes of residue gas and of gas plant products delivered from each lease; and
(iii) Third, calculate the theoretical quantities of net plant output of residue gas and of gas plant products attributable to each lease by multiplying the net plant output of residue gas, or gas plant products, by the ratio in which the theoretical volumes of residue gas, or gas plant products, is the numerator and the theoretical volume of residue gas, or gas plant products, delivered from all leases is the denominator.
(4) You may request MMS approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If MMS approves a different method, it will be applicable to all gas production from your Indian leases that is processed in the same plant.
(e) You may not take any deductions from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas incurred prior to the facility measurement point will not be subject to royalty if BLM determines that the loss was unavoidable.
(a) This section applies if the gas produced from your Indian lease is processed and that Indian lease requires accounting for comparison (also referred to as actual dual accounting). Except as provided in paragraphs (b) and (c) of this section, the actual dual accounting value, for royalty purposes, is the greater of the following two values:
(1) The combined value of the following products:
(i) The residue gas and gas plant products resulting from processing the gas determined under either § 206.172 or § 206.174, less any applicable allowances; and
(ii) Any drip condensate associated with the processed gas recovered downstream of the point of royalty settlement without resorting to processing determined under § 206.52, less applicable allowances.
(2) The value of the gas prior to processing determined under either § 206.172 or § 206.174, including any applicable allowances.
(b) If you are required to account for comparison, you may elect to use the alternative dual accounting methodology provided for in § 206.173 instead of the provisions in paragraph (a) of this section.
(c) Accounting for comparison is not required for gas if no gas from the lease is processed until after the gas flows into a pipeline with an index located in an index zone or into a mainline pipeline not in an index zone. If you do not perform dual accounting, you must certify to MMS that gas flows into such a pipeline before it is processed.
(d) Except as provided in paragraph (e) of this section, if you value any gas production from a lease for a month using the dual accounting provisions of this section or the alternative dual accounting methodology of § 206.173, then the value of that gas is the minimum value for any other gas production from that lease for that month flowing through the same facility measurement point.
(e) If the weighted-average Btu quality for your lease is less than 1,000 Btu's per cubic foot, see § 206.173(b)(4)(ii) to determine if you must perform a dual accounting calculation.
(a) When you value gas under § 206.174 at a point off the lease, unit, or communitized area (for example, sales point or point of value determination), you may deduct from value a transportation allowance to reflect the value, for royalty purposes, at the lease, unit, or communitized area. The allowance is based on the reasonable actual costs you incurred to transport unprocessed gas, residue gas, or gas plant products from a lease to a point off the lease, unit, or communitized area. This would include, if appropriate, transportation from the lease to a gas processing plant off the lease, unit, or communitized
(b) You must allocate transportation costs among all products you produce and transport as provided in § 206.178.
(c)(1) Except as provided in paragraphs (c)(2) and (3) of this section, your transportation allowance deduction for each selling arrangement may not exceed 50 percent of the value of the unprocessed gas, residue gas, or gas plant product. For purposes of this section, natural gas liquids are considered one product.
(2) If you ask MMS, MMS may approve a transportation allowance deduction in excess of the limitations in paragraph (c)(1) of this section. To receive this approval, you must demonstrate that the transportation costs incurred in excess of the limitations in paragraph (c)(1) of this section were reasonable, actual, and necessary. Under no circumstances may an allowance reduce the value for royalty purposes under any selling arrangement to zero.
(3) Your application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination.
(d) If MMS conducts a review or audit and determines that you have improperly determined a transportation allowance authorized by this subpart, then you will be required to pay any additional royalties, plus interest determined in accordance with 30 CFR 218.54. Alternatively, you may be entitled to a credit, but you will not receive any interest on your overpayment.
(a)
(i) If you have an arm's-length contract for transportation of your production, the transportation allowance is the reasonable, actual costs you incur for transporting the unprocessed gas, residue gas and/or gas plant products under that contract. Paragraphs (a)(1)(ii) and (iii) of this section provide a limited exception. You have the burden of demonstrating that your contract is arm's-length. Your allowances also are subject to paragraph (e) of this section. You are required to submit to MMS a copy of your arm's-length transportation contract(s) and all subsequent amendments to the contract(s) within 2 months of the date MMS receives your report which claims the allowance on the Form MMS-2014.
(ii) When either MMS or a tribe conducts reviews and audits, they will examine whether or not the contract reflects more than the consideration actually transferred either directly or indirectly from you to the transporter of the transportation. If the contract reflects more than the total consideration, then MMS may require that the transportation allowance be determined under paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the value of the transportation because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the transportation allowance be determined under paragraph (b) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your transportation costs.
(2) This paragraph explains how to allocate the costs to each product if your arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract.
(i) If your arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract, the total transportation costs must be allocated in a consistent and equitable manner to each of the products transported. To make this allocation, use the same proportion as
(ii) As an alternative to paragraph (a)(2)(i) of this section, you may propose to MMS a cost allocation method based on the values of the products transported. MMS will approve the method if we determine that it meets one of the two following requirements:
(A) The methodology in paragraph (a)(2)(i) of this section cannot be applied; and
(B) Your proposal is more reasonable than the methodology in paragraph (a)(2)(i) of this section.
(3) This paragraph explains how to allocate costs to each product if your arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract.
(i) If your arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract, you must propose an allocation procedure to MMS. You may use the transportation allowance determined in accordance with your proposed allocation procedure until MMS decides whether to accept your cost allocation.
(ii) You are required to submit all relevant data to support your allocation proposal. MMS will then determine the gas transportation allowance based upon your proposal and any additional information MMS deems necessary.
(4) If your payments for transportation under an arm's-length contract are not based on a dollar per unit price, you must convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(5) Where an arm's-length sales contract price includes a reduction for a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. You may use the transportation factor to determine your gross proceeds for the sale of the product. However, the transportation factor may not exceed 50 percent of the base price of the product without MMS approval.
(b)
(i) When you have a non-arm's-length transportation contract or no contract, including those situations where you perform transportation services for yourself, the transportation allowance is based upon your reasonable, allowable, actual costs for transportation as provided in this paragraph.
(ii) All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and adjustment. You must submit the actual cost information to support the allowance to MMS on Form MMS-4295, Gas Transportation Allowance Report, within 3 months after the end of the 12-month period to which the allowance applies. However, MMS may approve a longer time period. MMS will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may require you to modify your actual transportation allowance deduction.
(2) This paragraph explains what actual transportation costs are allowable under a non-arm's-length contract or no contract situation. The transportation allowance for non-arm's-length or no-contract situations is based upon your actual costs for transportation during the reporting period. Allowable costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment (in accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets
(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expense that you can document.
(ii) Allowable maintenance expenses include maintenance of the transportation system, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that you can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) You may use either depreciation with a return on undepreciated capital investment or a return on depreciable capital investment. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without MMS approval.
(A) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the transportation system services, or a unit of production method. Once you make an election, you may not change methods without MMS approval. A change in ownership of a transportation system will not alter the depreciation schedule that the original transporter/lessee established for purposes of the allowance calculation. With or without a change in ownership, a transportation system may be depreciated only once. Equipment may not be depreciated below a reasonable salvage value. To compute a return on undepreciated capital investment, you will multiply the undepreciated capital investment in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section.
(B) To compute a return on depreciable capital investment, you will multiply the initial capital investment in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance will be provided for depreciation. This alternative will apply only to transportation facilities first placed in service after March 1, 1988.
(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return is the monthly average rate as published in
(3) This paragraph explains how to allocate transportation costs to each product and transportation system.
(i) The deduction for transportation costs must be determined based on your cost of transporting each product through each individual transportation system. If you transport more than one product in a gaseous phase, the allocation of costs to each of the products transported must be made in a consistent and equitable manner. The allocation should be in the same proportion that the volume of each product (excluding waste products that have no value) bears to the volume of all products in the gaseous phase (excluding waste products that have no value). Except as provided in this paragraph, you may not take an allowance for transporting a product that is not royalty bearing without MMS approval.
(ii) As an alternative to the requirements of paragraph (b)(3)(i) of this section, you may propose to MMS a cost allocation method based on the values of the products transported. MMS will approve the method upon determining that it meets one of the two following requirements:
(A) The methodology in paragraph (b)(3)(i) of this section cannot be applied; and
(B) Your proposal is more reasonable than the method in paragraph (b)(3)(i) of this section.
(4) Your transportation allowance under this paragraph (b) must be determined based upon a calendar year or other period if you and MMS agree to an alternative.
(5) If you transport both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to MMS. You may use the transportation allowance determined in accordance with your proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. You are required to submit all relevant data to support your proposal. MMS will then determine the transportation allowance based upon your proposal and any additional information MMS deems necessary.
(c)
(2) Your election to use the alternative transportation allowance calculation in paragraph (c)(1) of this section must be made at the beginning of a month and must remain in effect for an entire calendar year. Your first election will remain in effect until the end of the succeeding calendar year, except for elections effective January 1 that will be effective only for that calendar year.
(d)
(2) You must report transportation allowances as a separate line item on Form MMS-2014. MMS may approve a different reporting procedure on allottee leases, and with lessor approval on tribal leases.
(e)
(f)
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(g)
(1)
(2)
(3)
(i)
(ii)
(iii)
(iv)
(4)
(5)
(h)
(a) When you value any gas plant product under § 206.174, you may deduct from value the reasonable actual costs of processing.
(b) You must allocate processing costs among the gas plant products. You must determine a separate processing allowance for each gas plant product and processing plant relationship. Natural gas liquids are considered as one product.
(c) The processing allowance deduction based on an individual product may not exceed 66 2/3 percent of the value of each gas plant product determined under § 206.174. Before you calculate the 66 2/3 percent limit, you must first reduce the value for any transportation allowances related to post-processing transportation authorized under § 206.177.
(d) Processing cost deductions will not be allowed for placing lease products in marketable condition. These costs include among others, dehydration, separation, compression upstream of the facility measurement point, or storage, even if those functions are performed off the lease or at a processing plant. Costs for the removal of acid gases, commonly referred to as sweetening, are not allowed unless the acid gases removed are further processed into a gas plant product. In such event, you will be eligible for a processing allowance determined under this subpart. However, MMS will not grant any processing allowance for processing lease production that is not royalty bearing.
(e) You will be allowed a reasonable amount of residue gas royalty free for operation of the processing plant, but no allowance will be made for expenses incidental to marketing, except as provided in 30 CFR part 206. In those situations where a processing plant processes gas from more than one lease, only that proportionate share of your residue gas necessary for the operation of the processing plant will be allowed royalty free.
(f) You do not owe royalty on residue gas, or any gas plant product resulting from processing gas, that is reinjected into a reservoir within the same lease, unit, or approved Federal agreement, until such time as those products are finally produced from the reservoir for sale or other disposition. This paragraph applies only when the reinjection is included in a BLM-approved plan of development or operations.
(g) If MMS determines that you have determined an improper processing allowance authorized by this subpart, then you will be required to pay any additional royalties plus late payment interest determined under 30 CFR 218.54. Alternatively, you may be entitled to a credit, but you will not receive any interest on your overpayment.
(a)
(i) The processing allowance is the reasonable actual costs you incur to process the gas under that contract. Paragraphs (a)(1)(ii) and (iii) of this section provide a limited exception. You have the burden of demonstrating that your contract is arm's-length. You are required to submit to MMS a copy of your arm's-length contract(s) and all subsequent amendments to the contract(s) within 2 months of the date MMS receives your first report that deducts the allowance on the Form MMS-2014.
(ii) When MMS conducts reviews and audits, we will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from you to the processor for the processing. If the contract reflects more than the total consideration, then MMS may require that the processing allowance be determined under paragraph (b) of this section.
(iii) If MMS determines that the consideration paid under an arm's-length processing contract does not reflect the value of the processing because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the processing allowance be determined under paragraph (b) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your processing costs.
(2) If your arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product can be determined from the contract, then the processing costs for each gas plant product must be determined in accordance with the contract. You may not take an allowance for the costs of processing lease production that is not royalty-bearing.
(3) If your arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product cannot be determined from the contract, you must propose an allocation procedure to MMS. You may use your proposed
(4) If your payments for processing under an arm's-length contract are not based on a dollar per unit price, you must convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b)
(i) If you have a non-arm's-length contract or no contract, the processing allowance is based upon your reasonable actual costs of processing as provided in paragraph (b)(2) of this section.
(ii) All processing allowances deducted under a non-arm's-length or no-contract situation are subject to monitoring, review, audit, and adjustment. You must submit the actual cost information to support the allowance to MMS on Form MMS-4109, Gas Processing Allowance Summary Report, within 3 months after the end of the 12-month period for which the allowance applies. MMS may approve a longer time period. MMS will monitor the allowance deduction to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may require you to modify your processing allowance.
(2) The processing allowance for non-arm's-length or no-contract situations is based upon your actual costs for processing during the reporting period. Allowable costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment (in accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the processing plant.
(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expense that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the processing plant, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that you can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the processing plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.
(iv) You may use either depreciation with a return on undepreciable capital investment or a return on depreciable capital investment. After you elect to use either method for a processing plant, you may not later elect to change to the other alternative without MMS approval.
(A) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the processing plant services, or a unit-of-production method. Once you make an election, you may not change methods without MMS approval. A change in ownership of a processing plant will not alter the depreciation schedule that the original processor/lessee established for purposes of the allowance calculation. However, for processing plants you or your affiliate purchase that do not have a previously claimed MMS depreciation schedule, you may treat the processing plant as a newly installed facility for depreciation purposes. A processing plant may be depreciated only once, regardless of whether there is a change in ownership. Equipment
(B) To compute a return on depreciable capital investment, you must multiply the initial capital investment in the processing plant by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance will be provided for depreciation. This alternative will apply only to plants first placed in service after March 1, 1988.
(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return is the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3) Your processing allowance under this paragraph (b) must be determined based upon a calendar year or other period if you and MMS agree to an alternative.
(4) The processing allowance for each gas plant product must be determined based on your reasonable and actual cost of processing the gas. You must base your allocation of costs to each gas plant product upon generally accepted accounting principles. You may not take an allowance for the costs of processing lease production that is not royalty-bearing.
(c)
(2) You must report gas processing allowances as a separate line item on the Form MMS-2014. MMS may approve a different reporting procedure for allottee leases, and with lessor approval on tribal leases.
(d)
(e)
Where accounting for comparison (dual accounting) is required for gas production from a lease but neither you nor someone acting on your behalf processes the gas, and you have elected to perform actual dual accounting under § 206.176, you must use the first applicable of the following methods to establish processing costs for dual accounting purposes:
(a) The average of the costs established in your current arm's-length processing agreements for gas from the lease, provided that some gas has previously been processed under these agreements.
(b) The average of the costs established in your current arm's-length processing agreements for gas from the lease, provided that the agreements are in effect for plants to which the lease is physically connected and under which gas from other leases in the field or area is being or has been processed.
(c) A proposed comparable processing fee submitted to either the tribe and MMS (for tribal leases) or MMS (for allotted leases) with your supporting documentation submitted to MMS. If MMS does not take action on your proposal within 120 days, the proposal will be deemed to be denied and subject to appeal to the MMS Director under 30 CFR part 290.
(d) Processing costs based on the regulations in §§ 206.179 and 206.180.
(a) This subpart is applicable to all coal produced from Federal coal leases. The purpose of this subpart is to establish the value of coal produced for royalty purposes, of all coal from Federal leases consistent with the mineral leasing laws, other applicable laws and lease terms.
(b) If the specific provisions of any statute or settlement agreement between the United States and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart then the statute, lease provision, or settlement shall govern to the extent of that inconsistency.
(c) All royalty payments made to the Mineral Management Service (MMS) are subject to later audit and adjustment.
(a) Ownership in excess of 50 percent constitutes control;
(b) Ownership of 10 through 50 percent creates a presumption of control; and
(c) Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates.
The information collection requirements contained in this subpart have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501
(a) All coal (except coal unavoidably lost as determined by BLM under 43 CFR part 3400) from a Federal lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in
(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; i.e., underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Federal leases shall be allocated to such leases regardless of whether it is stored on Federal lands. The lessee shall maintain accurate records to determine to which individual Federal lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid.
(a) For leases subject to § 206.257 of this subpart, the quality of coal on which royalty is due shall be reported on the basis of percent sulfur, percent ash, and number of British thermal units (Btu) per pound of coal. Coal quality determinations shall be made at intervals prescribed in the lessee's sales contract. If there is no contract, or if the contract does not specify the intervals of coal quality determination, the lessee shall propose a quality test schedule to MMS. In no case, however, shall quality tests be performed less than quarterly using standard industry-recognized testing methods. Coal quality information shall be reported on the appropriate forms required under 30 CFR part 216.
(b) For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information shall be reported on appropriate forms required under 30 CFR part 216 and on the Report of Sales and Royalty Remittance, Form MMS-2014, as required under 30 CFR part 210.
(a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Federal coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and MMS.
(b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. MMS may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource.
(c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 206.256(d) of this subpart.
(a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty on a cents-per-ton (or other quantity) basis.
(b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determine by BLM pursuant to 43 CFR part 3400.
(c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal.
(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced
(a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the value of coal determined under this section, less applicable coal washing allowances and transportation allowances determined under §§ 206.258 through 206.262 of this subpart, or any allowance authorized by § 206.265 of this subpart. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease.
(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then the MMS may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration.
(3) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the coal production be valued pursuant to paragraph (c)(2) (ii), (iii), (iv), or (v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported coal value.
(4) The MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to MMS's satisfaction, were not part of the total consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm's-length contract shall be determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition of produced coal by other than an arm's-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm's-length contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain types of coal;
(v) If a reasonable value cannot be determined using paragraphs (c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back method or any other reasonable method shall be used to determine value.
(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require MMS's prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm's-length sales value and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section. The notification shall be by letter to the Associate Director for Royalty Management of his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the Form MMS-2014 using a valuation method authorized by paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section, and each time there is a change in a method under paragraphs (c)(2) (iv) or (v) of this section.
(e) If MMS determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also be liable for interest computed pursuant to 30 CFR 218.202. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.
(g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 206.258 through 206.262 and § 206.265 of this subpart.
(h) The lessee is required to place coal in marketable condition at no cost to the Federal Government. Where the value established under this section is
(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless MMS approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal.
(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation proposals, including transportation, coal washing, or other allowances under § 206.265 of this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.
(a) For ad valorem leases subject to § 206.257 of this subpart, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 206.257 of this subpart was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.
(b) If MMS determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with 30 CFR 218.202, or shall be entitled to a credit without interest.
(c) Lessees shall not disproportionately allocate washing costs to Federal leases.
(d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing.
(e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid.
(a)
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then the MMS may require that the washing allowance be determined in accordance with paragraph (b) of this section.
(3) If the MMS determines that the consideration paid pursuant to an arm's-length washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the washing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed.
(b)
(2) The washing allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv) (A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes, rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalities, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is
(B) The MMS shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989.
(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3) The washing allowance for coal shall be determined based on the lessee's reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing.
(c)
(ii) The MMS may require that a lessee submit arm's-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(2)
(ii) For new washing facilities or arrangements, the lessee's initial washing deduction shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the washing system or, if such data are not available, the lessee shall use estimates based upon industry data for similar washing systems.
(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.
(d)
(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.
(e)
(2) The lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(f)
(a) When coal is subjected to washing, the washed coal must be allocated
(b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant.
(c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed.
(a) For ad valorem leases subject to § 206.257 of this subpart, where the value for royalty purposes has been determined at a point remote from the lease or mine, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:
(1) Transport the coal from a Federal lease to a sales point which is remote from both the lease and mine; or
(2) Transport the coal from a Federal lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.
(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported.
(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation costs to Federal leases.
(a)
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then the MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.
(3) If the MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of
(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b)
(2) The transportation allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of the MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.
(B) The MMS shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(B)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to
(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.
(3) A lessee may apply to MMS for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (b)(2) of this section. MMS will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency or by a State regulatory agency (for Federal leases). MMS shall deny the exception request if it determines that the rate is excessive as compared to arm's-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:
(i) No Federal or State regulatory agency costs analysis exists and the Federal or State regulatory agency, as applicable, has declined to investigate under MMS timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for transportation as determined under this section.
(c)
(ii) The MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(2)
(ii) For new transportation facilities or arrangements, the lessee's initial deduction shall include estimates of the allowable coal transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.
(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.
(iv) If the lessee is authorized to use its Federal- or State-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(d)
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.
(e)
(2) The lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payments, in accordance with instructions provided by MMS.
(f)
(a) The lessee and other payors shall submit to MMS, upon request, contracts for the sale of coal from ad valorem leases subject to this subpart. The MMS must receive the contracts within a reasonable period of time, as specified by MMS. Lessees shall include as part of the submittal requirements any contracts, agreements, contract amendments, or other documents that affect the gross proceeds received for the sale of coal, as well as any other information regarding any consideration received for the sale or disposition of coal that is not included in such contracts. At the time of its contract submittals, MMS may require the lessee to certify in writing that it has provided all documents and information that reflect the total consideration provided by purchasers of coal from ad valorem leases subject to this subpart. Information requested under this section may include contracts for both ad valorem and cents-per-ton leases and shall be available in the lessee's offices during normal business hours or provided to MMS at such time and in such manner as may be requested by authorized Department of the Interior personnel. Any oral sales arrangement negotiated by the lessee must be placed in a written form and be retained by the lessee. Nothing in this section shall be construed to limit the authority of MMS to obtain or have access to information pursuant to 30 CFR part 212.
(b) Lessees and other payors shall designate, for each contract submitted under this section, whether the contract is arm's-length or non-arm's-length.
(c) A lessee's or other payor's determination that its contract is arm's-length is subject to future audit to verify that the contract meets the criteria of the arm's-length contract definition in § 206.251 of this subpart.
(d) Information required to be submitted under this section that constitutes trade secrets and commercial and financial information that is identified as privileged or confidential shall not be available for public inspection or made public or disclosed without the consent of the lessee or other payor, except as otherwise provided by law or regulation.
If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to MMS. The MMS will review the lessee's proposal and issue a value determination. The lessee may use its proposed value until MMS issues a value determination.
If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance with § 206.257(h) of this subpart, the lessee shall notify MMS that such processing is occurring or will occur. The value of that production shall be determined as follows:
(a) A value established for the feedstock coal in marketable condition by application of the provisions of § 206.257(c)(2)(i-iv) of this subpart; or,
(b) In the event that a value cannot be established in accordance with subsection (a), then the value of production will be determined in accordance with § 206.257(c)(2)(v) of this subpart and the value shall be the lessee's gross proceeds accruing from the disposition of the enhanced product, reduced by MMS-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor's BBB bond rate applicable under § 206.259(b)(2)(v) of this subpart.
(a) The gross value for royalty purposes shall be the sale or contract unit price times the number of units sold,
(1) That a contract of sale or other business arrangement between the lessee and a purchaser of some or all of the commodities produced from the lease is not a bona fide transaction between independent parties because it is based in whole or in part upon considerations other than the value of the commodities, or
(2) That no bona fide sales price is received for some or all of such commodities because the lessee is consuming them, the authorized officer shall determine their gross value, taking into account: (i) All prices received by the lessee in all bona fide transactions, (ii) Prices paid for commodities of like quality produced from the same general area, and (iii) Such other relevant factors as the authorized officer may deem appropriate; and
(b) The lessee is required to certify that the values reported for royalty purposes are bona fide sales not involving considerations other than the sale of the mineral, and he may be required by the authorized officer to supply supporting information.
(a) This subpart is applicable to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970, as amended (30 U.S.C. 1001
(b) All royalty payments made to MMS are subject to audit and adjustment.
For purposes of this subpart:
(1) Ownership in excess of 50 percent constitutes control;
(2) Ownership of 10 through 50 percent creates a rebuttable presumption of control; and
(3) Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates.
(1) Any mineral or minerals (exclusive of oil, hydrocarbon gas, and helium) which are found in solution or developed in association with geothermal fluids and which have a value of less than 75 per centum of the value of the geothermal energy or are not, because of quantity, quality, or technical difficulties in extraction and production, of sufficient value to warrant extraction and production by themselves, and
(2) Commercially demineralized water.
(1) All products of geothermal processes, including indigenous steam, hot water, and hot brines;
(2) Steam and other gases, hot water, and hot brines resulting from water, gas, or other fluids artificially introduced into geothermal formations;
(3) Heat or other associated energy found in geothermal formations; and
(4) Any byproducts.
(a) The value of geothermal resources produced from leases subject to this subpart and used to generate electricity shall be determined pursuant to this section.
(b)(1)(i) The value of geothermal resources that are sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value that the lessee reports for royalty purposes is subject to monitoring, review, and audit.
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to the seller for the geothermal resource. If the contract does not reflect the total consideration, MMS may require that the
(iii) If MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS shall require the geothermal resource to be valued pursuant to paragraph (d) of this section, and notification provided to MMS in accordance with paragraph (e)(3) of this section. If MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's value.
(2) The MMS may require a lessee to certify that the provisions in its arm's-length contract include all of the consideration to be paid by the buyer, either directly or indirectly, for the geothermal resource.
(c)(1) The value of geothermal resources subject to this section that are sold under a non-arm's-length contract shall be determined in accordance with the first applicable of the following paragraphs:
(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract provided that those gross proceeds are not less than the gross proceeds derived from or paid under the lowest-priced available comparable arm's-length contract for sales of geothermal resources to the lessee-affiliate's same powerplant (the “minimum value”). If the gross proceeds under the lessee's non-arm's-length contract are less than the “minimum value” under available comparable arm's-length contracts, or if there are no available comparable arm's-length contracts, value will be determined by the weighted average of the gross proceeds established under arm's-length contracts for the sale of significant quantities of geothermal resources to the same powerplant. Available contracts will mean contracts in the possession of the lessee, the lessee's affiliate, or MMS. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: Time of execution, duration, terms, quality of the geothermal resource, volume, dedication to the same powerplant, and other factors that may be appropriate to reflect the value of the resource;
(ii) The value determined by the geothermal netback procedure. Under the geothermal netback procedure, the lessee's reasonable actual costs for the generation and transmission of electricity shall be deducted from the lessee's gross proceeds received for the sale of electricity to determine the value of the geothermal resource. Transmission deductions shall be determined pursuant to § 206.353 of this part. Generating deductions shall be determined pursuant to § 206.354 of this part; or
(iii) A value determined by any other reasonable valuation method approved by MMS.
(2) Value determinations made pursuant to this paragraph are subject to the notification requirements of paragraph (e) of this section.
(d)(1) The value of geothermal resources subject to this section that are not subject to a sales transaction (“no sales” geothermal resources) but are instead utilized directly by the lessee in its own powerplant for the generation and sale of electricity shall be determined in accordance with the first applicable of the following paragraphs:
(i) The weighted average of the gross proceeds established in arm's-length contracts for the purchase of significant quantities of geothermal resources to operate the lessee's same powerplant. In evaluating the acceptability of arm's-length contracts, the following factors shall be considered: Time of execution, duration, terms, volume, quality of resource, and such other factors as may be appropriate to reflect the value of the resource;
(ii) The value determined by the geothermal netback procedure. Under the geothermal netback procedure, the lessee's reasonable actual costs for the
(iii) A value determined by any other reasonable valuation method approved by MMS.
(2) Value determinations made pursuant to this paragraph are subject to the notification requirements of paragraph (e) of this section.
(e)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall retain all data relevant to the determination of royalty value, particularly where the value is determined pursuant to paragraph (c) or (d) of this section. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) Upon request, lessees shall make available to authorized MMS representatives or to other authorized persons any and all contracts for the sale or other disposition of the lease production; contracts for the sale, generation, and/or transmission of electricity attributable to lease production; and any arm's-length sales and other data for like-quality production sold, purchased, or otherwise obtained by the lessee from the field as may be necessary to support a value determination.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraph (c) or (d) of this section. The notification shall be by letter to the MMS Associate Director for Royalty Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c) or (d) of this section.
(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest on that difference computed pursuant to 30 CFR 218.302. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method and may use that method in determining value, for royalty purposes, until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination, MMS may use any of the valuation criteria consistent with this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee where geothermal resources are directly sold.
(i) The lessee is required to place geothermal resources in marketable condition and to deliver geothermal resources to the powerplant at no cost to the Federal lessor. Where the value established pursuant to this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the geothermal resource in marketable condition or deliver it to the powerplant.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed.
(l) Certain information submitted to MMS to support value determinations is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this subpart are to be submitted in accordance with the Freedom of Information Act regulations of the Department, 43 CFR part 2.
(a) Where the value of geothermal energy is determined by the geothermal netback procedure pursuant to paragraphs (c)(1)(ii) and (d)(1)(ii) of § 206.352 of this subpart, a transmission deduction shall be subtracted from the lessee's gross proceeds received for the sale of electricity to determine the plant tailgate value of the electricity. The transmission deduction consists of either or both of two components:
(1) Transmission line costs as determined pursuant to paragraph (b) of this section, and
(2) Wheeling costs if the electricity is transmitted across a third-party's transmission line under an arm's-length wheeling agreement. Transmission deductions are subject to the limitation prescribed in paragraph (c) of this section.
(b)(1) Transmission-line costs shall be based on the lessee's actual costs associated with the construction and operation of a transmission line for the purpose of transmitting electricity attributable and allocable to the lessee's powerplant utilizing Federal geothermal resources. The monthly transmission line cost component of the transmission deduction is determined by multiplying the annual transmission line cost rate (in dollars per kilowatthour) by the amount of electricity delivered for the reporting month. The transmission line cost rate shall be redetermined annually at the beginning of the same month of the year in which the transmission line was placed into service, the same month of the year in which the powerplant was placed into service, or, at the lessee's option, at a time concurrent with the beginning of the lessee's annual corporate accounting period;
(2) Allowable transmission-line costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the capital investment in the transmission line multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable assets, including costs of delivery and installation of capital equipment, that
(i) Allowable operating expenses include operations supervision and engineering, operations labor, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expenses that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the transmission line, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the transmission line is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval.
(A) To compute depreciation, the lessee must use a straight-line depreciation method based on the expected life of the geothermal project, usually the term of the electricity sales contract or other depreciation period acceptable to MMS. A change in ownership of a transmission line shall not alter the depreciation schedule established by the original lessee-owner for purposes of computing transmission line costs. With or without a change in ownership, a transmission line shall be depreciated only once. The rate of return used to compute the return on undepreciated capital investment shall be determined pursuant to paragraph (b)(2)(v) of this section.
(B) To compute a return on capital investment, the allowed cost shall be the amount equal to the allowable capital investment in the transmission line multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transmission lines first placed into service on or after March 1, 1988.
(v) The rate of return shall be 2 times Standard and Poor's industrial BBB bond rate. The rate of return shall be 2 times the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the annual deduction period and shall be effective during the following deduction period. The rate shall be redetermined annually at the beginning of the same month beginning the annual deduction period chosen pursuant to paragraph (b)(1) of this section.
(3) Transmission-line cost rates, determined annually, are computed by dividing the sum of the operating, maintenance, overhead, and capital costs by the annual amount of delivered electricity.
(4) For new transmission lines, the lessee's costs for the first deduction period shall be based on estimated expenses (including overhead) for operating and maintaining the transmission line. For subsequent deduction periods, the transmission line costs shall be estimated based on the lessee's actual operating and maintenance expenses for the previous period adjusted for decreases or increases that the lessee knows will affect the deduction in the current period.
(c) Under no circumstances shall the transmission deduction plus the generating deduction determined pursuant to § 206.354 of this subpart reduce the royalty value of the geothermal resource to zero.
(d)(1) If the actual transmission deduction determined at the end of the annual reporting period is less than the amount the lessee estimated and used in the netback procedure during the reporting period, the lessee shall be required to pay additional royalties retroactive to the first month of the reporting period, plus interest computed
(2) Lessees must submit corrected Forms MMS-2014 to reflect adjustments to royalty payments in accordance with MMS instructions.
(e)(1) All transmission deductions are subject to review, audit, and adjustment. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual transmission deduction and adjust royalty values accordingly.
(2) Pursuant to subpart H of 30 CFR part 212, the lessee must maintain all data and records supporting its transmission deduction, including wheeling and other transmission-related agreements. These data and records must be made available to MMS and other authorized personnel upon request, and shall be maintained in a confidential manner in accordance with applicable laws and regulations pursuant to § 206.352 of this subpart.
(f) A one-time refund of royalties equal to the royalty amount of actual dismantlement costs attributable to the transmission line that are in excess of actual income attributable to the salvage of the transmission line will be allowed at the completion of the dismantlement and salvage operations.
(a) Where the value of geothermal energy is determined by the geothermal netback procedure pursuant to paragraphs (c)(1)(ii) and (d)(1)(ii) of § 206.352 of this subpart, that value shall be determined by deducting the lessee's reasonable actual costs incurred to generate electricity from the plant tailgate value of the electricity (usually the transmission-reduced value of the delivered electricity). Generating deductions are subject to the limitation prescribed in paragraph (c) of this section.
(b)(1) Generating costs shall be based on the lessee's actual annual costs associated with the construction and operation of a geothermal powerplant. The monthly generating deduction is determined by multiplying the annual generating cost rate (in dollars per kilowatthour) by the amount of plant tailgate electricity measured (or computed) for the reporting month. The generating cost rate is determined from the annual amount of plant tailgate electricity and must be redetermined annually at the beginning of the same month of the year in which the powerplant was placed into service or, at the lessee's option, at a time concurrent with the beginning of the lessee's annual corporate accounting period;
(2) Allowable generating costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the capital investment in the powerplant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable assets, including costs of delivery and installation of capital equipment, that are an integral part of the powerplant or are required by the design specifications of the power conversion cycle. A return on capital invested in the purchase of real estate for a powerplant site may be allowed provided that the lessee demonstrates the necessity for such purchase, the purchased land is not on a Federal geothermal lease, and MMS approves the deduction; the rate of return shall be the same rate determined in paragraph (b)(2)(v) of this section. The costs of gathering systems and other production-related facilities are not allowed.
(i) Allowable operating expenses include operations supervision and engineering, operations labor, materials, ad valorem property taxes, rent, supplies, auxiliary fuel and/or utilities used to operate the powerplant during down time, and any other directly allocable and attributable operating expense that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the powerplant, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that the lessee can document.
(iii) Overhead directly attributable and allocable to the operation and maintenance of the powerplant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.
(iv) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval.
(A) To compute depreciation, the lessee must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract or other depreciation period acceptable to MMS. A change in ownership of a powerplant shall not alter the depreciation schedule established by the original lessee-owner for computing the generating costs. With or without a change in ownership, a powerplant shall be depreciated only once. The rate of return used to compute the return on undepreciated capital investment shall be determined pursuant to paragraph (b)(2)(v) of this section.
(B) To compute a return on capital investment, the allowed cost shall be the amount equal to the allowable capital investment in the powerplant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to powerplants first placed into service on or after March 1, 1988.
(v) The rate of return shall be 2 times Standard and Poor's industrial BBB bond rate. The rate of return shall be 2 times the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the annual deduction period and shall be effective during the following deduction period. The rate shall be redetermined annually at the beginning of the same month beginning the annual deduction period chosen pursuant to paragraph (b)(1) of this section.
(3) Generating cost rates, determined annually, shall be computed by dividing the sum of the operating, maintenance, overhead, and capital costs by the annual amount of plant tailgate electricity.
(4) For new powerplants, the lessee's generating costs for the first deduction period shall be based on estimated expenses (including overhead) for operating and maintaining the powerplant. For subsequent deduction periods, the generating costs shall be estimated based on the lessee's actual operating and maintenance expenses for the previous period adjusted for decreases or increases that the lessee knows will affect the deduction in the current period.
(c) Under no circumstances shall the generating deduction plus the transmission deduction determined pursuant to § 206.353 of this subpart reduce the royalty value of the geothermal resource to zero.
(d)(1) If the actual generating deduction determined at the end of the annual reporting period is less than the amount the lessee estimated and used in the netback procedure during the reporting period, the lessee shall be required to pay additional royalties retroactive to the first month of the reporting period, plus interest computed pursuant to 30 CFR 218.302. If the actual generating deduction is greater than the amount applied in the netback calculation, the lessee shall be entitled to a credit.
(2) Lessees must submit corrected Forms MMS-2014 to reflect adjustments to royalty payments in accordance with MMS instructions.
(e)(1) All generating deductions are subject to review, audit, and adjustment. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual generating deduction and adjust royalty values accordingly.
(2) Pursuant to subpart H of 30 CFR part 212, the lessee must maintain all data and records supporting its generating deduction. These data and records must be made available to
(f) A one-time refund of royalties equal to the royalty amount of actual dismantlement costs attributable to the powerplant that are in excess of actual income attributable to the salvage of the powerplant will be allowed at the completion of the dismantlement and salvage operations.
(a) The value of geothermal resources produced for leases subject to this subpart and used in direct utilization processes shall be determined pursuant to this section.
(b)(1)(i) The value of geothermal resources that are sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value that the lessee reports for royalty purposes is subject to monitoring, review, and audit.
(ii) In conducting these reviews and audits, MMS will examine whether or not the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the geothermal resource. If the contract does not reflect the total consideration, MMS may require that the geothermal resource sold pursuant to that contract be valued in accordance with paragraph (d) of this section. Value shall not be less than the gross proceeds accruing to the lessee, including any additional consideration received.
(iii) If MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the geothermal resource because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS shall require the geothermal resource to be valued pursuant to paragraph (d) of this section and in accordance with the notification requirements of paragraph (e) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's value.
(2) The MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the geothermal resource.
(c)(1) The value of geothermal resources subject to this section that are sold under a non-arm's-length contract shall be determined in accordance with the first applicable of the following paragraphs:
(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract provided that those gross proceeds are not less than the gross proceeds derived from or paid under the lowest-priced available comparable arm's-length contract for sales of geothermal resources to the lessee-affiliate's same direct utilization facility (the “minimun value”). If the gross proceeds under the lessee's non-arm's-length contract are less than the “minimum value” under available comparable arm's-length contracts, or if there are no available comparable arm's-length contracts, value will be determined by the weighted average of the gross proceeds established under arm's-length contracts for the sale of significant quantities of geothermal resources to the same direct utilization facility. Available contracts will mean contracts in the possession of the lessee, the lessee's affiliate, or MMS. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: Time of execution, duration, terms, quality of the geothermal resource, volume, dedication to the same direct utilization facility, and other factors that may be appropriate to reflect the value of the resource;
(ii) The equivalent value of the least expensive, reasonable alternative energy source (fuel). The equivalent value of the least expensive, reasonable alternative energy source shall be
(iii) A value determined by any other reasonable valuation method approved by MMS.
(2) Valuations made pursuant to this paragraph are subject to the notification requirements of paragraph (e) of this section.
(d)(1) The value of geothermal resources subject to this section that are not subject to a sales transaction but are instead used by the lessee in its own direct utilization facility (“no sales” geothermal resources) shall be determined in accordance with the first applicable of the following paragraphs:
(i) The weighted average of the gross proceeds established in arm's-length contracts for the purchase of significant quantities of geothermal resources to operate the lessee's same direct utilization facility. In evaluating the acceptability of arm's-length contracts, the following factors shall be considered: Time of execution, duration, terms, volume, quality of resource, and such other factors as may be appropriate to reflect the value of the resource;
(ii) The equivalent value of the least expensive, reasonable alternative energy source (fuel). The equivalent value of the least expensive, reasonable alternative energy source shall be based on the amount of thermal energy that would otherwise be used by the direct utilization process in place of the geothermal resource. That amount of thermal energy (in Btu's) displaced by the geothermal resource shall be determined by the equation
(iii) A value determined by any other reasonable valuation method approved by MMS.
(2) Valuations made pursuant to this paragraph are subject to the notification requirements of paragraph (e) of this section.
(e)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall retain all data relevant to the determination of royalty value, particularly where the value is determined pursuant to paragraph (c) or (d) of this section. Such data shall be subject to review and audit, and MMS will direct a lessee to
(2) Upon request, lessees shall make available to authorized MMS representatives or to other authorized persons any and all contracts for the sale or other disposition of the lease production, and any arm's-length sales and other data for like-quality production sold, purchased, or otherwise obtained by the lessee from the field as may be necessary to support a value determination.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraph (c) or (d) of this section. The notification shall be by letter to the MMS Associate Director for Royalty Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c) or (d) of this section.
(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest on that difference computed pursuant to 30 CFR 218.302. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method and may use that method in determining value, for royalty purposes, until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination, MMS may use any of the valuation criteria consistent with this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make adjustments in accordance with paragraph (f) of this section.
(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production, for royalty purposes, be less than the gross proceeds accruing to the lessee where geothermal energy is directly sold.
(i) The lessee is required to place geothermal resources in marketable condition and to deliver geothermal resources to the direct utilization facility at no cost to the Federal lessor. Where the value established pursuant to this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the geothermal resource in marketable condition or to deliver it to the direct utilization facility.
(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to the contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee shall owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of geothermal resources.
(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or
(l) Certain information submitted to MMS to support value determinations is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt will be maintained in a confidential manner in accordance with applicable laws and regulations. All requests for information about determinations made under this subpart are to be submitted in accordance with the Freedom of Information Act regulation of the Department, 43 CFR part 2.
(a) The value of geothermal byproducts, including commercially demineralized water, shall be determined pursuant to this section, less applicable byproducts transportation allowances determined pursuant to §§ 206.357 and 206.358 of this subpart.
(b)(1)(i) The value of byproducts that are sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value that the lessee reports for royalty purposes is subject to monitoring, review, and audit.
(ii) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to the seller for the byproducts. If the contract does not reflect the total consideration, MMS may require that the byproducts sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including any additional consideration received .
(iii) If MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS shall require that the byproduct production be valued pursuant to paragraph (c) of this section and in accordance with the notification requirements of paragraph (d) of this section. If MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported byproduct value.
(2) The MMS may require a lessee to certify that the provisions in its arm's-length contract include all of the consideration to be paid by the buyer, either directly or indirectly, for the byproduct.
(c) The value of byproducts that are sold pursuant to a non-arm's-length contract or that are utilized by the lessee (no sales), except demineralized water used for the benefit of the lease pursuant to paragraph (b)(2) of § 202.351 of this subpart, shall be determined in accordance with the first applicable of the following paragraphs:
(1) The gross proceeds accruing to the lessee pursuant to a sale under its non arm's-length contract (or other disposition by other than an arm's-length contract), provided that those gross proceeds are not less than the gross proceeds derived from or paid under the lowest-priced available comparable arm's-length contract for sales, purchases, or other dispositions of like-quality byproducts in the field or, if necessary to obtain a representative sample, from the same area (the “minimum value”). If the gross proceeds under the lessee's non-arm's-length contract are less than the “minimum value” under available comparable arms length contracts, or if there are no available comparable arm's-length contracts, value will be determined by the weighted average of the gross proceeds established under arm's-length contracts for the sale of like-quality
(2) Other relevant matters including, but not limited to, published or publicly available spot-market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain byproducts; or
(3) A netback method or any other reasonable method used to determine value.
(d)(1) Pursuant to subpart H of 30 CFR part 212, the lessee shall retain all data relevant to the determination of royalty value, particularly where the value is determined pursuant to paragraph (c) of this section. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) Upon request, lessees shall make available to authorized MMS representatives or to other authorized persons any and all contracts and/or invoices for the sale or other disposition of the byproducts, and any arm's-length sales and other data for like-quality production sold, purchased, or otherwise obtained by the lessee from the field or other area as may be necessary to support a value determination.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraph (c) of this section. The notification shall be by letter to the MMS Associate Director for Royalty Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c) of this section, and each time there is a change in a method under paragraph (c) of this section.
(e) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest on that difference computed pursuant to 30 CFR 218.302. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method and may use that method in determining value, for royalty purposes, until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination, MMS may use any of the valuation criteria consistent with this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.
(g) Notwithstanding any other provisions of the section, under no circumstances shall the value of byproducts for royalty purposes be less than the gross proceeds accruing to the lessee, less applicable byproduct transportation allowances determined pursuant to §§ 206.357 and 206.358 of this subpart.
(h) The lessee is required to place the byproducts in marketable condition at no cost to the Federal Government. Where the value established pursuant to this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the byproducts in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to the contract, and may be retroactively applied to value byproducts, for royalty purposes, for a period not to exceed 2 years, unless MMS approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of byproducts.
(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding against the Federal Government or its beneficiaries until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation proposals, including byproduct transportation allowances pursuant to §§ 206.357 and 206.358 of this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552. Any data specified by the act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable laws and regulations. All requests for information about determinations made under this subpart are to be submitted in accordance with the Freedom of Information Act regulation of the Department, 43 CFR part 2.
(a) Where the value of byproducts has been determined at a point off the geothermal lease, unit, or participating area, MMS shall allow a deduction in determining value, for royalty purposes, for the lessee's reasonable, actual costs incurred to:
(1) Transport the byproducts from a Federal lease, unit, or participating area to a sales point or point of delivery that is off the lease, unit, or participating area; or
(2) Transport the byproducts from a Federal lease, unit, or participating area, or from a geothermal utilization facility to a byproduct recovery facility when that byproduct recovery facility is off the lease, unit, or participating area and, if applicable, from the recovery facility to a sales point or point of delivery off the lease, unit, or participating area. Costs for transporting geothermal fluids from the lease to the geothermal utilization facility, whether on or off the lease, shall not be included in the transportation allowance.
(b) Under no circumstances shall the byproduct transportation allowance authorized by paragraph (a) of this section reduce the value of the byproducts under any selling arrangement to zero.
(c)(1) When byproducts are transported from a lease, unit, participating area, or geothermal utilization facility to a byproduct recovery facility, the lessee is not required to allocate transportation costs between the quantity of marketable byproducts and the rejected waste material. The byproduct transportation allowance shall be authorized for the total production that is transported. Byproduct transportation allowances shall be expressed as a cost per unit of marketable byproducts transported.
(2) For byproducts that are extracted on the lease, unit, or participating area, or at the geothermal utilization facility, the byproduct transportation allowance shall be authorized for the total production that is transported to a point of sale off the lease, unit, or participating area. Byproduct transportation allowances shall be expressed as a cost per unit of byproduct transported.
(3) Transportation costs shall be authorized as allowances only when the transported byproduct is sold, delivered, or otherwise utilized by the lessee and royalties are reported and paid.
(d) Byproduct transportation allowances are subject to monitoring, review, and audit. If, after a review and/or audit, MMS determines that a lessee has improperly determined a byproduct transportation allowance authorized by this section, then the lessee shall pay any additional royalties plus interest determined in accordance with 30 CFR 218.302, or shall be entitled to a credit without interest.
(e) If byproducts produced from Federal and non-Federal leases are commingled for transportation, lessees shall not disproportionately allocate transportation costs to Federal lease production.
(f) Upon request, the lessee shall make available to authorized MMS representatives or to other authorized persons all transportation contracts and all other information as may be necessary to support a byproduct transportation allowance.
(g) Byproduct transportation allowances are to be reported as separate lines on Form MMS-2014.
(a)
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, MMS may require that the byproduct transportation allowance be determined in accordance with paragraph (b) of this section.
(3) If MMS determines that the consideration paid pursuant to an arm's-length byproduct transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS shall require that the byproduct transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-length contract are not established on a dollars-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b)
(2) The byproduct transportation allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the capital investment in the transportation system
(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other allocable and attributable operating expenses that the lessee can document.
(ii) Allowable maintenance expenses include maintenance of the transportation system, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) To compute costs associated with capital investment, a lessee may use either paragraph (b)(2)(iv)(A) or (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without MMS approval.
(A) To compute depreciation, the lessee must use a straight-line depreciation method based on, as appropriate, either the life of equipment or the life of the geothermal project that the transportation system services. After an election is made, the lessee may not change methods. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value. The rate of return used to compute the return on undepreciated capital investment shall be determined pursuant to paragraph (b)(2)(v) of this section.
(B) To compute a return on capital investment, the allowed cost shall be the amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation.
(v) The rate of return shall be Standard and Poor's industrial BBB bond rate. The rate of return shall be the monthly average rate as published in
(a) This subpart prescribes the procedures to establish the value, for royalty purposes, of all coal from Indian Tribal and allotted leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma).
(b) If the specific provisions of any statute, treaty, or settlement agreement between the Indian lessor and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart, then the statute, treaty, lease provision, or settlement shall govern to the extent of that inconsistency.
(c) All royalty payments are subject to later audit and adjustment.
(d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian coal leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.
(a) All coal (except coal unavoidably lost as determined by BLM pursuant to 43 CFR group 3400) from an Indian lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease.
(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses.
(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; i.e., underground mining method or surface mining method. Coal in waste pits or
(a) For leases subject to § 206.456 of this subpart, the quality of coal on which royalty is due shall be reported on the basis of percent sulfur, percent ash, and number of British thermal units (Btu) per pound of coal. Coal quality determinations shall be made at intervals prescribed in the lessee's sales contract. If there is no contract, or if the contract does not specify the intervals of coal quality determination, the lessee shall propose a quality test schedule to MMS. In no case, however, shall quality tests be performed less than quarterly using standard industry-recognized testing methods. Coal quality information shall be reported on the appropriate forms required under 30 CFR part 216.
(b) For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information shall be reported on appropriate forms required under 30 CFR part 216 and on the Report of Sales and Royalty Remittance, Form MMS-2014, as required under 30 CFR part 210.
(a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Indian coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and MMS.
(b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. MMS may ask BLM or BIA to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource.
(c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 206.455(d) of this subpart.
(a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty on a cents-per-ton (or other quantity) basis.
(b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determined by BLM pursuant to 43 CFR part 3400.
(c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal.
(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 206.456 of this subpart, and royalties shall be paid at the royalty rate specified in the readjusted lease.
(a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County,
(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit.
(2) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then MMS may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration.
(3) If MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the coal production be valued pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported coal value.
(4) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production.
(5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to MMS’ satisfaction, were not part of the total consideration paid for the purchase of coal production.
(c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm's-length contract shall be determined in accordance with this section.
(2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion:
(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition of produced coal by other than an arm's-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm's-length contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal;
(ii) Prices reported for that coal to a public utility commission;
(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;
(iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a
(v) If a reasonable value cannot be determined using paragraphs (c)(2)(i), (c)(2)(ii), (c)(2)(iii), or (c)(2)(iv) of this section, then a net-back method or any other reasonable method shall be used to determine value.
(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.
(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require MMS’ prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.
(2) An Indian lessee will make available upon request to the authorized MMS or Indian representatives, or to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm's-length sales and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area.
(3) A lessee shall notify MMS if it has determined value pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section. The notification shall be by letter to the Associate Director for Royalty Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the Form MMS-2014 using a valuation method authorized by paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section, and each time there is a change in a method under paragraphs (c)(2)(iv) or (c)(2)(v) of this section.
(e) If MMS determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also be liable for interest computed pursuant to 30 CFR 218.202. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.
(f) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.
(g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 206.457 through 206.461 and § 206.464 of this subpart.
(h) The lessee is required to place coal in marketable condition at no cost to the Indian lessor. Where the value established pursuant to this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition.
(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by
(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Indian Tribes or allottees until the audit period is formally closed.
(k) Certain information submitted to MMS to support valuation proposals, including transportation, coal washing, or other allowances pursuant to §§ 206.457 through 206.461 and § 206.464 of this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. Nothing in this section is intended to limit or diminish in any manner whatsoever the right of an Indian lessor to obtain any and all information as such lessor may be lawfully entitled from MMS or such lessor's lessee directly under the terms of the lease or applicable law.
(a) For ad valorem leases subject to § 206.456 of this subpart, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 206.456 of this subpart was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.
(b) If MMS determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.
(c) Lessees shall not disproportionately allocate washing costs to Indian leases.
(d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing.
(e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid.
(a)
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then MMS may require that the washing allowance be determined in accordance with paragraph (b) of this section.
(3) If MMS determines that the consideration paid pursuant to an arm's-length washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the washing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's washing costs.
(4) Where the lessee's payments for washing under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed.
(b)
(2) The washing allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-
(B) MMS shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989.
(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent washing allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section).
(3) The washing allowance for coal shall be determined based on the lessee's reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing.
(c)
(ii) The initial Form MMS-4292 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4292 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) MMS may require that a lessee submit arm's-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(v) Washing allowances which are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.
(2)
(ii) The initial Form MMS-4292 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the washing under the non-arm's-length contract or the no contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4292 containing the actual costs for the previous reporting period. If coal washing is continuing, the lessee shall include on Form MMS-4292 its estimated costs for the next calendar year. The estimated coal washing allowance shall be based on the actual costs for the previous period plus or minus any adjustments which are based on the lessee's knowledge of decreases or increases which will affect the allowance. Form MMS-4292 must be received by MMS within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) For new wash plants, the lessee's initial Form MMS-4292 shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant, or if such data are not available, the lessee shall use estimates based upon industry data for similar coal wash plants.
(v) Washing allowances based on non-arm's-length or no contract situations which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used by the lessee to prepare its Forms MMS-4292. The data shall be provided within a reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.
(3) MMS may establish coal washing allowance reporting dates for individual leases different from those specified in this subpart in order to provide more effective administration. Lessees will be notified of any change in their reporting period.
(4) Washing allowances must be reported as a separate line on the Form MMS-2014, unless MMS approves a different reporting procedure.
(d)
(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.
(e)
(2) The lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(f)
(a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted.
(b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant.
(c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed.
(a) For ad valorem leases subject to § 206.456 of this subpart, where the value for royalty purposes has been determined at a point remote from the lease or mine, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:
(1) Transport the coal from an Indian lease to a sales point which is remote from both the lease and mine; or
(2) Transport the coal from an Indian lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance.
(b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.
(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported.
(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported.
(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid.
(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.
(e) Lessees shall not disproportionately allocate transportation costs to Indian leases.
(a)
(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to
(3) If MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.
(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.
(b)
(2) The transportation allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.
(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.
(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.
(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.
(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of MMS.
(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the
(B) MMS shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(B)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989.
(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average as published in Standard and Poor's Bond Guide for the first month of the reporting period of which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent transportation allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section).
(3) A lessee may apply to MMS for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (b)(2) of this section. MMS will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency for Indian leases. MMS shall deny the exception request if it determines that the rate is excessive as compared to arm's-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:
(i) No Federal regulatory agency cost analysis exists and the Federal regulatory agency has declined to investigate pursuant to MMS timely objections upon filing; and
(ii) The rate significantly exceeds the lessee's actual costs for transportation as determined under this section.
(c)
(ii) The initial Form MMS-4293 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.
(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4293 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period). Lessees may request special reporting procedures in unique allowance reporting situations, such as those related to spot sales.
(iv) MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.
(v) Transportation allowances that are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect
(vi) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.
(2)
(ii) The initial Form MMS-4293 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the transportation under the non-arm's-length contract or the no contract situation terminates, whichever is earlier.
(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4293 containing the actual costs for the previous reporting period. If the transportation is continuing, the lessee shall include on Form MMS-4293 its estimated costs for the next calendar year. The estimated transportation allowance shall be based on the actual costs for the previous reporting period plus or minus any adjustments that are based on the lessee's knowledge of decreases or increases that will affect the allowance. Form MMS-4293 must be received by MMS within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).
(iv) For new transportation facilities or arrangements, the lessee's initial Form MMS-4293 shall include estimates of the allowable transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system, or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.
(v) Non-arm's-length contract or no contract-based transportation allowances that are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.
(vi) Upon request by MMS, the lessee shall submit all data used to prepare its Form MMS-4293. The data shall be provided within a reasonable period of time, as determined by MMS.
(vii) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.
(viii) If the lessee is authorized to use its Federal-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.
(3) MMS may establish reporting dates for individual lessees different than those specified in this paragraph in order to provide more effective administration. Lessees will be notified as to any change in their reporting period.
(4) Transportation allowances must be reported as a separate line item on Form MMS-2014, unless MMS approves a different reporting procedure.
(d)
(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.
(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.
(e)
(2) The lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.
(f)
(a) The lessee and other payors shall submit to MMS, upon request, contracts for the sale of coal from ad valorem leases subject to this subpart. MMS must receive the contracts within a reasonable period of time, as specified by MMS. Lessees shall include as part of the submittal requirements any contracts, agreements, contract amendments, or other documents that affect the gross proceeds received for the sale of coal, as well as any other information regarding any consideration received for the sale or disposition of coal that is not included in such contracts. At the time of its contract submittals, MMS may require the lessee to certify in writing that it has provided all documents and information that reflect the total consideration provided by purchasers of coal from ad valorem leases subject to this subpart. Information requested under this section may include contracts for both ad valorem and cents-per-ton leases and shall be available in the lessee's offices during normal business hours or provided to MMS at such time and in such manner as may be requested by authorized Department of the Interior personnel. Any oral sales arrangement negotiated by the lessee must be placed in a written form and be retained by the lessee. Nothing in this section shall be construed to limit the authority of MMS to obtain or have access to information pursuant to 30 CFR part 212.
(b) Lessees and other payors shall designate, for each contract submitted pursuant to this section, whether the contract is arm's-length or non-arm's-length.
(c) A lessee's or other payor's determination that its contract is arm's-length is subject to future audit to verify that the contract meets the criteria of the arm's-length contract definition in § 206.451 of this subpart.
(d) Information required to be submitted under this section that constitutes trade secrets and commercial and financial information that is identified as privileged or confidential shall not be available for public inspection or made public or disclosed without the consent of the lessee or other payor, except as otherwise provided by law or regulation.
If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to MMS. MMS will review the lessee's proposal and issue a value determination. The lessee may use its proposed value until MMS issues a value determination.
If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance
(a) A value established for the feedstock coal in marketable condition by application of the provisions of § 206.456(c)(2) (i) through (iv) of this subpart; or,
(b) In the event that a value cannot be established in accordance with paragraph (a) of this section, then the value of production will be determined in accordance with § 206.456(c)(2)(v) of this subpart and the value shall be the lessee's gross proceeds accruing from the disposition of the enhanced product, reduced by MMS-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor's BBB bond rate applicable under § 206.458(b)(2)(v) of this subpart.
5 U.S.C. 301
(a) The information collection and recordkeeping requirements contained in this part have been approved by OMB under 44 U.S.C. 3501
(b) Public reporting burden is estimated to average 30 minutes per year for each record keeper to maintain copies of sales contracts, agreements, or other documents relevant to the valuation of production. Send any comments regarding this burden estimate or any other aspect of this requirement to the Information Collection Clearance Officer, Minerals Management Service, 381 Elden Street, Herndon, VA 22070, and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Paperwork Reduction Project 1010-0061, Washington, DC 20503.
The definitions in part 206 of this title are applicable to this part.
On November 29, 1950 (15 FR 8585), a new lease form was adopted (Form 4-1158, 15 FR 8585) containing provisions whereby the lessee agrees that nothing in any contract or other arrangement made for the sale or disposal of oil, gas, natural gasoline, and other products of the leased land, shall be construed as modifying any of the provisions of the lease, including, but not limited to, provisions relating to gas waste, taking royalty-in-kind, and the method of computing royalties due as based on a minimum valuation and in accordance with the oil and gas valuation regulations. A contract or agreement pursuant to a lease containing such provisions may be made without obtaining prior approval of the United States as lessor, but must be retained as provided in § 207.5 of this subpart.
(a) Old form leases are those containing provisions prohibiting sales or disposal of oil, gas, natural gasoline, and other products of the lease except in accordance with a contract or other arrangement approved by the Secretary of the Interior, or by the Director of the Minerals Management Service or his/her representative. A contract or agreement made pursuant to an old form lease may be made without obtaining approval if the contract or agreement contains either the substance of or is accompanied by the stipulation set forth in paragraph (b) of this section, signed by the seller (lessee or operator).
(b) The stipulation, the substance of which must be included in the contract, or be made the subject matter of a separate instrument properly identifying the leases affected thereby, is as follows:
It is hereby understood and agreed that nothing in the written contract or in any approval thereof shall be construed as affecting any of the relations between the United States and its lessee, particularly in matters of gas waste, taking royalty in kind, and the method of computing royalties due as based on a minimum valuation and in accordance with the terms and provisions of the oil and gas valuation regulations applicable to the lands covered by said contract.
Copies of all sales contracts, posted price bulletins, etc., and copies of all agreements, other contracts, or other documents which are relevant to the valuation of production are to be maintained by the lessee and made available upon request during normal working hours to authorized MMS, State or Indian representatives, other MMS or BLM officials, auditors of the General Accounting Office, or other persons authorized to receive such documents, or shall be submitted to MMS within a reasonable period of time, as determined by MMS. Any oral sales arrangement negotiated by the lessee must be placed in written form and retained by the lessee. Records shall be retained in accordance with 30 CFR part 212.
5 U.S.C. 301
The regulations in this part govern the sale of royalty oil by the United States to eligible refiners. The regulations apply to royalty oil from leases on Federal lands onshore and on the Outer Continental Shelf (OCS).
(1) For the purchase of royalty oil from onshore leases, it means a refiner that qualifies as a small and independent refiner as those terms are defined in sections 3(3) and 3(4) of the Emergency Petroleum Allocation Act, 15 U.S.C. 751
(2) For the purchase of royalty oil from leases on the OCS, it means a refiner that qualifies as a small business enterprise under the rules of the Small
(2) If there were no such sales, or if the Secretary finds that there were an insufficient number of such sales to equitably determine such value, computed at the average unit price at which oil was sold pursuant to other leases in the same region of the OCS during such period, or
(3) If there were no sales of oil from such region during such period, or if the Secretary finds that there are an insufficient number of such sales to equitably determine such value, at an appropriate price determined by the Secretary.
The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501
(a)
(b)
(2) All sales of royalty oil from onshore leases will be priced at the royalty value that would have been determined for that oil pursuant to 30 CFR part 206 had the royalties been paid in value rather than taken in kind. All sales of royalty oil from OCS leases will be priced at the fair market value of the oil including associated transportation costs to the designated delivery point, if applicable.
(3) An eligible refiner must have a representative at a sale in order to participate. The Secretary may, at his or her discretion, establish purchase limitations and withhold any royalty oil from any offering.
(4) The MMS will recover the administrative costs of the RIK Program through the collection of administrative fees. The fees will consist of an initial nonrefundable contract fee for each executed contract and a monthly variable charge applied to each lease under contract. The amount of the initial contract fee shall be determined prior to a sale and published in the “Notice of Availability of Royalty Oil.” The initial contract fee will be payable in equal installments due at the end of the first and second months of the contract. These contract fees will be applied against the RIK Program's administrative costs, and the remainder of the administrative costs will be recovered through the monthly variable charges per lease, which will be billed and payable concurrently with the monthly actual billings for royalty oil. The rate per lease will be determined by dividing the remaining recoverable administrative costs by the total number of leases under contract. The rate may change depending upon whether total administrative costs change and/or whether the number of leases taken in kind changes
(c) Upon a determination by the Secretary under paragraph (a) of this section that eligible refiners do have access to adequate supplies of crude oil at equitable prices, MMS will not take royalties in kind from oil and gas leases for exclusive sale to such refiners. Such determinations may be made on a regional basis.
(d)
If the Secretary decides to take royalty oil in kind for sale to eligible refiners, MMS will issue a “Notice of Availability of Royalty Oil” specifying the manner in which the sale is to be effected, the approximate quantity of royalty oil to be offered, information required in applications, the closing date for the receipt of applications for royalty oil, and other general administrative details concerning the application, allocation, and contract award process for the royalty oil. The Notice will describe generally the terms under which the royalty oil contracts will be awarded and will specify which applicants will be deemed preference eligible refiners in the sale proceedings. The Notice will also contain guidelines for reallocation procedures in the event substantial quantities of royalty oil sold in that specific sale are subsequently turned back to MMS. Only those purchasers that hold ongoing contracts from that specific sale will be allowed to participate in any reallocation, which would be voluntary, and then only if they continue to meet eligibility requirements as set forth in 30 CFR 208.2 and 208.7. If a reallocation is held prior to the effective date of the contracts as specified in the “Notice of Availability of Royalty Oil”, all eligible refiners that selected a lease or leases in that specific sale would be allowed to participate, pursuant to the procedures in the Notice.
(a) To apply for the purchase of royalty oil, an applicant must file a Form MMS-4070 with MMS in accordance with instructions provided in the “Notice of Availability of Royalty Oil” and in accordance with any instructions issued by MMS for completion of Form MMS-4070. The applicant will be required to submit a letter of intent from a qualified financial institution stating that it would be granted surety coverage for the royalty oil for which it is applying, or other such proof of surety coverage, as deemed acceptable by MMS. The letter of intent must be submitted with a completed Form MMS-4070.
(b) In addition to any other application requirements specified in the Notice, the following information is required on Form MMS-4070 at the time of application:
(1) Name and address of the applicant, the location of the applicant's refinery or refineries, and disclosure of the applicant's affiliation with any other persons.
(2) The capacity of the applicant's refineries in barrels of crude oil throughput per calendar day and a tabulation for the past 12 months of oil processed for each refinery, identified as to source (from own production or from other sources).
(3) Identification of any Government royalty oil contracts under which the applicant is currently receiving royalty oil.
(4) Identification of the locations (area/region and State) where the applicant proposes to purchase royalty
(5) A certification from the applicant that it is an eligible refiner for the purchase of Government royalty oil, as defined in § 208.2 of this part.
(a) The MMS will examine each application and may request additional information if the information in the application is inadequate. An application received after the close of the application period will be rejected. If additional information is requested by MMS, it must be received by the time specified or the application will be rejected.
(b) After the close of the application period and the receipt of any additional requested information, MMS will determine which applicants may participate in the royalty oil sale and the quantity of royalty oil which each applicant is authorized to purchase.
(c) When applications are filed by two or more eligible refiners for the same royalty oil, the oil will be allocated among such applicants on an equitable basis as determined by MMS. Preference eligible refiners will be given priority in the allocation procedures in sales and subsequent reallocations of royalty oil.
(d) No eligible refiner shall be awarded contracts for volumes of royalty oil that, when added to volumes of other Federal royalty oil being received, are in excess of 60 percent of the combined refinery capacity of that refiner.
(e) The MMS may exclude any section 6 lease from a royalty oil sale.
(f) If two or more eligible refiners are related through common ownership or control or otherwise affiliated, only one of them shall be entitled to an allotment of royalty oil from a specific sale.
(g) Any applicant whose refinery is not in operation during the 60-day period prior to the date of the royalty oil sale shall not be entitled to participate in the sale unless such applicant self-certifies and demonstrates to the satisfaction of MMS that it will begin operations by the first month in which oil becomes available under a royalty oil contract. If operations do not begin by that month, MMS will terminate the contract.
(h) Applicants or purchasers that have delinquent balances with MMS as of the date of a royalty oil sale or subsequent reallocation will not be allowed to participate in that sale or reallocation. If a person which is controlled by, in control of, under common control with, or otherwise affiliated with an applicant or purchaser has such delinquent balances, the applicant or purchaser will not be allowed to participate in a royalty oil sale or reallocation. To the extent a purchaser or affiliated person has appealed a billing and posted a surety instrument in accordance with the contract terms and applicable MMS regulations or other law, the balance shall not be considered delinquent.
(i) A purchaser must meet the eligibility criteria on the date of contract issuance. However, a change in a purchaser's eligibility status during the term of the contract will not affect the purchaser's right to continue that contract until its term expires, including any extensions thereof.
(a) The lessee shall deliver royalty oil from onshore leases to the purchaser at a point on or adjacent to the lease pursuant to the terms of the lease. If the purchaser does not have access to its onshore royalty oil entitlement at facilities on or adjacent to the lease, the operator of the lease must designate an alternate delivery point at no additional cost to the purchaser or the Government. The purchaser must have physical access to the oil at the alternate delivery point and such point must be approved by MMS.
(b) The lessee shall deliver royalty oil from section 8 offshore leases issued after September 1969 at a delivery point to be designated by MMS. The lessee shall deliver royalty oil from section 8 offshore leases issued before October 1969 or from section 6 leases at a delivery point to be designated by the
(c) When the purchaser has physical access to the royalty oil at the delivery point, the lessee shall deliver such oil in marketable condition at pipeline connections or other facilities designated by MMS. If the lessee is unable to provide the royalty portion of actual production from the lease, the lessee must provide crude oil to the purchaser which is equivalent in volume or value to the royalty oil to which the purchaser is entitled. The lessee will deliver the royalty oil to the purchaser during normal operating hours and in reasonable quantities and intervals. The lessee will make available and the purchaser will accept delivery of the royalty oil entitlement no later than the last day of the calendar month immediately following the calendar month in which the oil was produced. Failure to accept deliveries shall constitute grounds for the termination of the contract.
(d) Upon termination of deliveries under a royalty oil contract, the transportation allowance and delivery point designation authorized by this section no longer will remain in effect.
(a) A purchaser must submit to MMS two copies of any written third-party agreements, or two copies of a full written explanation of any oral third-party agreements, relating to the method and costs of delivery of royalty oil, or crude oil exchanged for the royalty oil, from the point of delivery under the contract to the purchaser's refinery. In addition, the purchaser must submit copies of agreements pertaining to quality differentials which may occur between leases and delivery points.
(b) A purchaser may not sell royalty oil which it purchases pursuant to this part except for purposes of an exchange for other crude oil on a volume or equivalent value basis.
(c) Royalty oil purchased under this part, or crude oil received in exchange for such royalty oil, must be processed into refined petroleum products in the purchaser's refinery.
(a) The MMS shall notify each operator, by certified mail, of the Secretary's decision to take royalty oil in kind. This notice shall be mailed at least 45 days in advance of the effective date of delivery and will specify delivery points for offshore oil for OCS leases issued after September 1969.
(b) Deliveries of royalty oil may be partially terminated only with the written approval of the Director, MMS.
(c) Before terminating the delivery of royalty oil taken in kind, MMS, if possible, will notify each operator by certified mail of the change in requirements at least 30 days in advance of the effective date.
(d) After MMS notification that royalty oil will be taken in kind, the operator shall be responsible for notifying each working interest on the Federal lease. As soon as practicable after the date of each royalty oil sale, MMS will publish in the
(e) A purchaser cannot transfer, assign, or sell its rights or interest in a royalty oil contract without written approval of the Director, MMS. If the purchaser changes ownership or its assets are sold or liquidated for any reason, it cannot transfer, assign, or sell its rights or interest in the royalty oil contract without written approval of the Director, MMS. Without express written consent from MMS for a change in ownership, the royalty oil contract shall be terminated. The successor company must meet the definition of an eligible refiner in § 208.2 of this part for MMS to consider assignment of the royalty oil contract.
(a) The eligible purchaser, prior to execution of the contract, shall furnish an “MMS-specified surety instrument,” in an amount equal to the estimated value of royalty oil that could be taken by the purchaser in a 99-day period, plus related administrative charges. The MMS may require the purchaser to increase the amount of the surety instrument when necessary to protect the Government's interest or may allow the purchaser to decrease the amount of the surety instrument where necessary to further the purposes of the Royalty-in-Kind Program.
(b) If a letter of credit is furnished as the surety instrument, it must be effective for a 9-month period beginning the first day the royalty oil contract is effective, with a clause providing for automatic renewal monthly for a new 9-month period. The purchaser or its surety company may elect not to renew the letter of credit at any monthly anniversary date, but must notify MMS of its intent not to renew at least 30 days prior to the anniversary date. The MMS may grant the purchaser 45 days to obtain a new surety instrument. If no replacement surety instrument is provided, MMS will terminate the contract effective at least 6 months prior to the expiration date of the letter of credit. Notwithstanding the above provisions, the letter of credit also may contain a clause providing for automatic termination 6 months after the royalty oil contract terminates. If a certificate of deposit is furnished as the surety instrument, it must be effective for the life of the contract plus 6 months after the royalty oil contract terminates.
(c) For the purposes of this section, an “MMS-specified surety instrument” means either: an MMS-specified surety bond, an MMS-specified irrevocable letter of credit, or a financial institution book-entry certificate of deposit.
(d) The “MMS-specified surety instrument” shall be in a form specified by MMS instructions or approved by MMS. A bond must be issued by a qualified surety company that has been approved by the Department of the Treasury. An irrevocable letter of credit or a certificate of deposit must be from a financial institution acceptable to MMS. The MMS will use a bank rating service to determine whether a financial institution has an acceptable rating to provide a surety instrument deemed adequate to indemnify the Government from loss or damage.
(e) All surety instruments must be in a form acceptable to MMS and must include such other specific requirements as MMS may require adequately to protect the Government's interests.
(a) All payments to MMS by a purchaser of royalty oil will be due on the date and at the location specified in the contract, or, if there is no contractual provision, as specified by MMS. The purchaser shall tender all payments to MMS in accordance with 30 CFR 218.51. Payments made by a payor pursuant to the requirements of paragraph (b) of this section and § 208.13 also shall be tendered in accordance with 30 CFR 218.51.
(b)(1) Payments from a purchaser of royalty oil not received by MMS when due, or that portion of the payment less than the full amount due, will be subject to a late payment charge equivalent to an interest assessment on the amount past due for the number of days that the payment is late at the underpayment rate applicable under section 6621 of the Internal Revenue Code of 1954.
(2) The MMS may assess interest to a payor for any underpayments which are the result of the payor's late or
(c) If payment for royalty oil is not received by the due date specified in the contract, a notice of nonreceipt will be sent to the purchaser by certified mail. If payment is not received by MMS within 15 days from the date of such notice, MMS may cancel the contract and collect under the MMS-specified surety instrument. See § 208.11.
(d) If the purchaser disagrees with the amount of payment due, it must pay the amount due as computed by MMS, unless the purchaser appeals the amount and posts an MMS-specified surety instrument pursuant to the provisions of 30 CFR part 243. The MMS may, at its discretion, waive the appeal surety requirements if it determines that the contract surety instrument is sufficient protection for an amount under appeal.
If MMS underbills a purchaser under a royalty oil contract because of a payor's underreporting or failure to report on Form MMS-2014 pursuant to 30 CFR 210.52, the payor will be liable for payment of such underbilled amounts plus interest if they are unrecoverable from the purchaser or the surety instrument related to the contract.
Failure to abide by the regulations in this part may result in civil and criminal penalties being levied on that person as specified in sections 109 and 110 of the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1719-20, and regulations at 30 CFR part 241. Civil penalties applicable under the OCSLA and the Mineral Leasing Act of 1920 may also be imposed.
Audits of the accounts and books of lessees, operators, payors, and/or purchasers of royalty oil taken in kind may be made annually or at such other times as may be directed by MMS. Such audits will be for the purpose of determining compliance with applicable statutes, regulations, and royalty oil contracts.
If you receive a contracting officer's decision, you may:
(a) Appeal that decision to the Board of Contract Appeals in the Office of Hearings and Appeals, Office of the Secretary, in accordance with the procedures provided in 43 CFR part 4, subpart C; or
(b) File an action in the United States Court of Federal Claims.
The Secretary of the Department of the Interior, upon a recommendation by the Secretary of Defense or the Secretary of Energy and with the approval of the President, may suspend operations under these regulations and suspend royalty oil contracts during a national emergency declared by the Congress or the President.
5 U.S.C. 301
(a)
(b)
(1) Requests for Forms MMS-2014 or MMS-4070 should be addressed to the Minerals Management Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado 80217-5760. The completed Form MMS-2014 should be mailed to the Minerals Management Service, Royalty Management Program, P.O. Box 5810, Denver, Colorado 80217-5810. The address to which a completed Form MMS-4070 should be mailed will be identified in a
(2) Requests for Forms MMS-4025 or MMS-4030 should be addressed to the Minerals Management Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado 80217-5760. The completed forms should be mailed to the same address.
(3) Requests for Forms MMS-3160, MMS-4051, MMS-4052, MMS-4053, MMS-4054, MMS-4055, MMS-4056, MMS-4057, MMS-4058, MMS-4059, MMS-4060, or MMS-4061 should be addressed to the Minerals Management Service, Royalty Management Program, P.O. Box 17110, Denver, Colorado 80217-0110. The completed forms should be mailed to the same address.
(4) Requests for processing or transportation allowance forms (Forms MMS-4109, MMS-4110, MMS-4292, MMS-4293, or MMS-4295) should be addressed to the Minerals Management Service, Royalty Management Program, P.O. Box 25165, Denver, Colorado 80225-0165. The completed allowance forms should be mailed to the Minerals Management Service, Royalty Management Program, P.O. Box 5200, Denver, Colorado 80217-5200.
(5) Requests for Form MMS-4280 should be addressed to the Minerals Management Service, Royalty Management Program, P.O. Box 25165, Denver, Colorado 80225-0165. The completed form should be mailed to the same address. (See 30 CFR 218.57(b)).
(6) Reports delivered to MMS by special couriers or overnight mail shall be addressed as follows: Minerals Management Service, Royalty Management Program, Building 85, Denver Federal Center, room A-212, Denver, Colorado 80225.
(c)
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(2)
(3)
(4)
(5)
(6)
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(10)
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(13)
(14)
(15)
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(d)
(a) You must submit Forms MMS-2014 and MMS-4054 to MMS electronically. You must begin reporting electronically according to the following timetable unless you qualify for the exceptions to electronic reporting listed in § 210.22:
(b) See § 218.40(c) for the definition of a royalty report line on Form MMS-2014 and § 216.40(c) for the definition of
(c) For purposes of this part, multiple submissions of the same form in one month equals one form.
(a) You may use any of the following electronic media types, unless MMS instructs you differently:
(1) Electronic Data Interchange (EDI)
(2) Electronic Mail (e-mail)
(i) Template—MMS-provided software that generates blank forms on a personal computer to assist companies in preparing MMS regulatory reports (this option is not available for Form MMS-4054);
(ii) Comma Separated Values (CSV)—A file format where attribute fields are separated by commas; and
(iii) American Standard Code for Information Interchange (ASCII)—A file format of fixed-length records with fixed-length attribute fields;
(3) Reporter-Prepared Diskette (3
(i) Template;
(ii) CSV; and
(iii) ASCII;
(4) Magnetic or Cartridge Tape—A data storage medium used to transmit report data in an ASCII file format.
(b) MMS prefers that you use the media types in the order presented in paragraph (a) of this section to the extent it is cost effective and practical. As technology changes, MMS will consider other media types and the order of MMS preference may change. Refer to our electronic commerce brochure for the most current reporting options. You can receive a copy of our brochure by calling your MMS representative or by accessing our Internet site at www.rmp.mms.gov.
(c) Before you may begin reporting electronically:
(1) You must submit an electronic sample of your report for MMS approval using the MMS-supplied electronic reporting guidelines;
(2) MMS must notify you that your sample report has been approved;
(3) MMS must assign you a sender identification number and security code for any EDI transmissions; and
(4) MMS must assign you an originating address and compression software password for any e-mail transmissions.
MMS will allow the following grace periods and exceptions to the electronic reporting requirements in § 210.20:
(a) If you become a new MMS reporter after any of the dates you are required to submit electronic reports under § 210.20(a), you have 3 months from the day your first report is due to begin reporting electronically;
(b) If you exceed the maximum number of lines you are allowed to report on paper under § 210.20(a), you have 3 months from the last day of the month in which you exceeded the line limit to begin reporting electronically;
(c) You are not required to report electronically if you report only rent, minimum royalty, or other annual obligations on the Form MMS-2014; and
(d) You are not required to report electronically if you are a small business as defined by the U.S. Small Business Administration, and you have no computer, no resources to purchase a computer or contract with an electronic reporting service, nor access to a computer at a local library or other public facility.
The Federal Oil and Gas Royalty Management Act of 1982 (30 U.S.C. 1701
Information required by the MMS shall be filed using the forms prescribed in this subpart, which are available from MMS. Records may be maintained in microfilm, microfiche, or other recorded media that is easily reproducible and readable.
The Payor Information Form (Form MMS-4025) must be filed for each Federal or Indian lease on which royalties are paid. Where specifically determined by MMS, Form MMS-4025 is also required for all Federal leases on which rent is due. The completed form must be filed by the party who is making the rent or royalty payment (payor) for each revenue source. Form MMS-4025 must be filed no later than 30 days after issuance of a new lease or a modification to an existing lease which changes the paying responsibility on the lease.
(a) You must submit a completed Form MMS-2014 (Report of Sales and Royalty Remittance) to MMS with:
(1) All royalty payments; and,
(2) Rents on nonproducing leases, where specified.
(b) When you submit Form MMS-2014 data electronically, you must not submit the form itself.
(c) Completed Forms MMS-2014 for royalty payments are due by the end of the month following the production month.
(d) Where applicable, completed Forms MMS-2014 for rental payments are due no later than the anniversary date of the lease.
(e) This section does not prohibit you from making early payments voluntarily.
(a) Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in an MMS “Oil and Gas Payor Handbook,” a “Production Accounting and Auditing System Reporter Handbook,” and a “PAAS Onshore Oil and Gas Reporter Handbook.” The Payor Handbook is available from the Minerals Management Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado 80217-5760. The Reporter Handbooks are available from the Minerals Management Service, Royalty Management Program, P.O. Box 17110, Denver, Colorado 80217-0110.
(b) Royalty payors or production reporters should refer to these handbooks for specific guidance with respect to oil and gas reporting requirements. If additional information is required, the payor or reporter should contact the MMS at the above address. The appropriate telephone numbers are listed in the handbooks.
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
(a) MMS may require you to submit additional information, forms, or reports other than those specifically referred to in this subpart. MMS will give you instructions for providing such information or filing such reports or forms. MMS will make requests for additional information, forms, or reports under this section in conformity with the Paperwork Reduction Act of 1995, 44 U.S.C. 3501, and other applicable laws.
(b) If you file a Form MMS-4025, Payor Information Form (PIF) under § 210.51, you must provide the following information to MMS upon request for each PIF:
(1) The AID number for the lease;
(2) The name, address, Taxpayer Identification Number (TIN), and
(3) Whether the person you named in paragraph (b)(2) of this section with respect to the lease for which you filed the PIF is a:
(i) Lessee of record (record title owner);
(ii) Operating rights owner (working interest owner); or
(iii) Operator;
(4) The name, address, and phone number of the individual to contact for the person you named in paragraph (b)(2) of this section;
(5) Your TIN; and
(6) Whether you are the Designee of the person you named in paragraph (b)(2) of this section under 30 U.S.C. 1712(a), and, if so:
(i) The date your designation became effective; and
(ii) The date your designation terminates, if applicable; and
(iii) A copy of the written designation;
(c) If you have been identified under paragraph (b)(2) of this section, you must provide the following information to MMS upon request:
(1) Confirmation that you are the person identified under paragraph (b)(2) of this section;
(2) Confirmation that the person identified in paragraph (b)(6) of this section is your designee; and
(3) A designation under § 218.52 of this title if the person identified in paragraph (b)(6) of this section is not your Designee, and if you are not reporting and paying royalties and making other payments to MMS.
Information required by the Minerals Management Service (MMS) shall be filed using the forms prescribed in this subpart, copies of which are available from MMS. Instructions on the completion of these forms are provided in the Payor Handbook—Solid Minerals, also available from MMS. Records and supporting data may be maintained in hardcopy, microfilm, microfiche, or other recorded media that is readily available and readable.
A Solid Minerals Payor Information Form (Form MMS-4030) must be submitted to MMS for each Federal and Indian solid minerals lease on which royalties, rentals or minimum royalties are paid. This form does not change any requirement for a separate approval, if required, by the Department of the Interior. The Form MMS-4030 shall identify the payor of rent, minimum royalty, advance royalty and production royalty, and identify revenue sources and selling arrangements for all lease products. The completed form must be filed by each royalty payor no later than 30 days after MMS provides notice that the payor is converted to the Auditing and Financial System (AFS). After filing the initial form, a new Form MMS-4030 must be filed no later than 30 days after the occurrence of any of the following:
(a) Assignment of all or any part of the lease;
(b) Adoption of a new mining method;
(c) Production of a new product;
(d) A change in a selling arrangement;
(e) Change in royalty rate;
(f) Change of payor; or
(g) Abandonment of a lease.
A completed Report of Sales and Royalty Remittance (Form MMS-2014) must accompany all payments to MMS for rents (other than first year) and royalties for Federal and Indian solid minerals leases. On leases where payment is remitted directly to an Indian tribe or Bureau of Indian Affairs office, the payor also must send a completed
The MMS may require submission of additional information on special forms or reports. When special forms or reports other than those referred to in this subpart are necessary, instructions for the filing of such forms or reports will be given by MMS. Requests for the submission of such forms will be made in conformity with the requirements of the Paperwork Reduction Act of 1980 and other applicable laws.
(a) Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in an “MMS Payor Handbook—Solid Minerals” and a “Production Accounting and Auditing System Reporter Handbook.” The Payor Handbook is available from the Minerals Management Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado 80217-5760. The Reporter Handbook is available from the Minerals Management Service, Royalty Management Program, P.O. Box 17110, Denver, Colorado 80217-0110.
(b) Royalty payors or production reporters should refer to these handbooks for specific guidance with respect to solid minerals reporting requirements. If additional information is required, the payor or reporter should contact the MMS at the above address. The appropriate telephone numbers are listed in the handbooks.
Terms used in this subpart shall have the same meaning as in 30 CFR 206.351.
Information required by MMS shall be filed using the forms prescribed in this subpart, which are available from MMS. Records may be maintained on microfilm, microfiche, or other recorded media that are easily reproducible and readable. See subpart H of 30 CFR part 212.
The Payor Information Form (Form MMS-4025) must be filed for each Federal lease on which geothermal royalties (including byproduct royalties) are paid. Where specifically determined by MMS, Form MMS-4025 is also required for all Federal leases on which rent is due. The completed form must be filed by the party who is making the rent or royalty payment (payor) for each revenue source. Form MMS-4025 must be filed no later than 30 days after issuance of a new lease or a modification to an existing lease that changes the paying responsibility on the lease. The Form MMS-4025 shall identify the payor of production royalty, and identify revenue sources and selling arrangements for all leased geothermal resources (including byproducts). After filing the initial form, a new Form MMS-4025 must be filed no later than 30 days after the occurrence of any of the following:
(a) Assignment of all or any part of the lease;
(b) Production of new product;
(c) A change in a selling arrangement;
(d) Change in royalty rate;
(e) Change of payor; or
(f) Abandonment of a lease.
The MMS may require submission of additional information on special forms or reports. When special forms or reports other than those referred to in this subpart are necessary, MMS will give instructions for the filing of such forms or reports. Requests for the submission of such forms will be made in conformity with the requirements of the Paperwork Reduction Act of 1980 and other applicable laws.
A completed Report of Sales and Royalty Remittance (Form MMS-2014) must be submitted each month once sales or utilization of production occur, even though sales may be intermittent, unless otherwise authorized by MMS. This report is due on or before the last day of the month following the month in which production was sold or utilized, together with the royalties due the United States.
(a) Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in an MMS Oil and Gas Payor Handbook which is available from the Minerals Management Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado 80217-5760.
(b) Royalty payors should refer to this handbook for specific guidance with respect to geothermal resources reporting requirements. If additional information is required, the payor should contact the MMS at the above address. The appropriate telephone numbers are listed in the handbook.
5 U.S.C. 301
All records pertaining to offshore and onshore Federal and Indian oil and gas leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the recordholder is notified, in writing, that records must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the recordholder is released by
(a)
(b)
(c)
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
(a) All records pertaining to Federal and Indian solid minerals leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the record holder is notified, in writing, that records must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the record holder is released by written notice of the obligation to maintain records.
(b) The MMS shall have access to all records of the operator/lessee pertaining to compliance to Federal royalties, including, but not limited to:
(1) Qualities and quantities of all products mined, processed, sold, delivered, or used by the operator/lessee.
(2) Prices received for mined or processed products, prices paid for like or similar products, and internal transfer prices.
(3) Costs of mining, processing, handling, and transportation.
Terms used in this subpart shall have the same meaning as in 30 CFR 206.351.
(a)
(b)
(c)
(1) Qualities and quantities of all products extracted, processed, sold, delivered, or used by the operator/lessee;
(2) Prices received for products, prices paid for like or similar products, and internal transfer prices; and
(3) Costs of extraction, power generation, electrical transmission, and byproduct transportation.
(d)
5 U.S.C. 301
The purpose of this part is to ensure that the Federal Government receives proper information regarding energy and mineral resources removed from Federal and Indian leases and federally approved agreements, including the Outer Continental Shelf (OCS).
This part governs the reporting of oil, gas, and solid minerals operations information on Federal and Indian leases or federally-approved agreements including leases or agreements on the OCS. This part also governs the reporting of other operational information associated with production from Federal and Indian leases or federally-approved agreements when such operations occur prior to the point of sale or royalty determination, whichever is applicable. Reporters are required to submit certain production reports to MMS as set forth in this part.
For purposes of this part:
The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10.
You must submit your Oil and Gas Operations Report, Form MMS-4054, in accordance with electronic reporting requirements in 30 CFR part 210.
(a) Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in a “PAAS Reporter Handbook” and a “Paas Onshore Oil and Gas Reporter Handbook.” The Reporter Handbooks are available from the Minerals Management Service, Royalty Management Program, P.O. Box 17110, Denver, Colorado 80217-0110.
(b) Production reporters should refer to these handbooks for specific guidance with respect to production reporting requirements. If additional information is required, the reporter should contact the MMS at the above address. The telephone number is listed in the handbooks.
(a) All reporting forms listed in this part that are mailed or sent by U.S. Postal Service express mail should be mailed to the Mineral Management Service, Royalty Management Program, P.O. Box 17110, Denver, Colorado 80217-0110.
(b) Reports delivered to MMS by special couriers or overnight mail, except U.S. Postal Service express mail, shall be addressed as follows: Minerals Management Service, Royalty Management Program, Building 85, Denver Federal Center, Denver, Colorado 80225.
(c) A report is considered received when it is delivered to MMS at the addresses specified in paragraphs (a) and (b) of this section. Reports received at the MMS addresses specified in paragraphs (a) and (b) of this section after 4 p.m. mountain time are considered received the following business day.
The requirements of this part shall apply to all oil, gas, and solid mineral operators reporting information on Federal and Indian leases or federally-approved agreements, including leases or agreements on the OCS.
The reporter shall submit accurately, completely and timely, pursuant to the requirements of this part, all information forms and other information required by MMS. Specific guidance on the use of the required forms is contained in the Production Accounting and Auditing System Reporters Handbook. Copies of the handbook are available from the MMS.
(a) Information obtained by MMS pursuant to the rules of this part shall be open for public inspection and copying during regular office hours upon a written request, pursuant to rules at 43 CFR part 2, except that:
(1) Notwithstanding any other provision of this part, information obtained from a reporter under this part relating to a minerals agreement approved pursuant to the Indian Mineral Development Act of 1982, 25 U.S.C. 2101
(2) Information obtained from a reporter pursuant to this part that constitutes a trade secret and/or commercial or financial information which is privileged or confidential, or other information that may be withheld under the Freedom of Information Act (5 U.S.C. 552(b)), such as geologic and geophysical data concerning wells, shall be available for public inspection in accordance with 43 CFR part 2. When such information is related to Indian lands, consent to release the information must also be obtained from the cognizant Tribe or allottee.
(b) If any geologic and/or geophysical data is submitted under this part, these shall be made available to the public only in accordance with the provisions of 30 CFR 250.3, 250.4 and 252.7, if these relate to an offshore lease, and in accordance with 43 CFR 3162.8 if these relate to an onshore Federal or Indian lease.
When special forms or reports other than those referred to in the regulations in this part are necessary, instructions for the filing of such forms or reports will be provided by the Associate Director. Such requests will be made in conformity with the requirements of the Paperwork Reduction Act of 1980, and are expected to involve less than 10 respondents annually.
(a) An assessment of an amount not to exceed $10 per day may be charged for each report not received by MMS by the designated due date.
(b) An assessment of an amount not to exceed $10 may be charged for each incorrectly completed report.
(c) For purposes of oil and gas reporting under the PAAS, a report is defined as each line of production information required on the Monthly Report of Operations (Form MMS-3160), Oil and Gas Operations Report (Form MMS-4054), Gas Analysis Report (Form MMS-4055), Gas Plant Operations Report (Form MMS-4056), and Production Allocation Schedule Report (Form MMS-4058).
(d) For purposes of solid minerals reporting under PAAS, a report is defined as each line of production information required on the Solid Minerals Operation Report (Form MMS-4059) and Solid Minerals Facility Report (Form MMS-4060).
(e) The MMS will not make assessments for reporting problems which are beyond the control of the reporter (e.g., reports received late because of bad weather). The reporter shall have the burden of proving that a reporting problem was unavoidable.
(f) An assessment under this section shall not be shared with a State, Indian tribe, Indian allottee, or Alaska Native Corporation.
(g) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by MMS. The assessment amount for each violation will be based on MMS's experience with costs and improper reporting. The MMS will publish a Notice of the assessment amount to be applied in the
(a) You must submit a Monthly Report of Operations, Form MMS-3160, if you operate either an onshore Federal or Indian lease or an onshore federally-approved agreement that contains one or more wells that are not permanently plugged and abandoned. You may submit Form MMS-3160 electronically.
(b) You must submit a Form MMS-3160 for each well for each calendar month, beginning with the month in which you complete drilling, unless you have only test production from a drilling well or MMS tells you in writing to do otherwise.
(c) MMS must receive your completed Form MMS-3160 according to the following table:
(d) You must continue reporting until either:
(1) BLM approves all wells as permanently plugged or abandoned and you dispose of all inventory; or
(2) The lease or agreement is terminated.
(e) You are not required to submit Form MMS-3160 if:
(1) You are authorized to submit an Oil and Gas Operations Report, Form MMS-4054, instead of a Form MMS-3160; or
(2) You operate a gas storage agreement. You must report gas storage agreements to the appropriate BLM office.
(f) Specific and detailed guidance on how to prepare and submit the required production data on the Form MMS-3160 are contained in the MMS
(g)(1) Operators already reporting onshore lease production data to MMS in accordance with § 216.53 of this part on the effective date of this rule may request to change to the provisions of this section. Any request to change to the requirements of this section must be made by advance written notice to MMS and have MMS approval.
(2) An operator who reports production data to MMS for offshore leases in accordance with § 216.53 of this part may request to report for its onshore leases in accordance with the requirements of that section. Any such request must be made by advance written notice to MMS and have MMS approval.
(h)(1) Except where disclosure is required by law, information submitted on Form MMS-3160 that MMS classifies as confidential will be protected as such by both MMS and BLM for the period of 1 year. Operators must petition MMS for each lease or agreement to obtain a confidential classification and to extend the classification period beyond 1 year.
(2) Except as provided by statute, information submitted on Form MMS-3160 in regard to Federal leases and Indian leases which are part of a unit containing non-Indian leases is not considered to be confidential.
(3) Except where disclosure is required by law, all information submitted on Form MMS-3160 in regard to Indian leases, other than those included in paragraph (d)(2) of this section, will be considered to be confidential.
(4) Except as provided in this subsection, all other information will be released.
A Facility and Measurement Information Form (Form MMS-4051) must be filed for each facility or measurement device which handles production from any Federal or Indian lease, or federally-approved agreement, through the point of first sale or the point of royalty computation, whichever is later. The completed form must be filed by any operator (reporting production on a Form MMS-4054) of an onshore Facility Measurement Point (FMP) that handles production from any Federal or Indian lease or federally-approved agreement prior to, or at the point of royalty determination, or any operator who acquires an onshore FMP that is currently reporting to the PAAS. The report must be filed no later than 30 days after the establishment of a new facility or measurement device, or 30 days after a change is made to an existing facility or measurement device.
The First Purchaser Report (Form MMS-4053) must be filed by first purchasers only upon the specific request of MMS.
(a) You must file an Oil and Gas Operations Report, Form MMS-4054, if you operate one of the following that contains one or more wells that are not permanently plugged or abandoned:
(1) An OCS lease or federally-approved agreement; or
(2) An onshore Federal or Indian lease or federally-approved agreement for which you elected to report on a Form MMS-4054 instead of a Form MMS-3160.
(b) You must submit a Form MMS-4054 for each well for each calendar month, beginning with the month in which you complete drilling, unless you have only test production from a drilling well or MMS tells you in writing to do otherwise.
(c) MMS must receive your completed Form MMS-4054 according to the following table:
(d) You must continue reporting until either:
(1) BLM or MMS approves all wells as permanently plugged or abandoned and you dispose of all inventory; or
(2) The lease or agreement is terminated.
When requested by MMS, any operator must file a Gas Analysis Report (GAR) (Form MMS-4055) for each royalty or allocation meter. The form must contain accurate and detailed gas analysis information. This requirement applies to offshore, onshore, or Indian leases.
(a) MMS may request a GAR when you sell gas, or transfer gas for processing, before the point of royalty computation.
(b) When MMS first requests this report, the report is due within 30 days. If MMS requests subsequent reports, they will be due no later than 45 days after the end of the month covered by the report.
(a) You must submit a Gas Plant Operations Report, Form MMS-4056, if you operate either:
(1) A gas plant that processes gas originating from an OCS lease or federally-approved agreement before the point of final royalty determination; or
(2) A gas plant that processes gas from an onshore Federal or Indian lease or federally-approved agreement before the point of final royalty determination, and MMS has asked you to submit a Form MMS-4056.
(b) You must submit a Form MMS-4056 for each calendar month beginning with the month gas processing is initiated.
(c) MMS must receive your completed Form MMS-4056 according to the following table:
(d) Your report must show 100 percent of the gas.
(e) You are not required to file a Form MMS-4056 if:
(1) Your plant has not processed gas that originated from a Federal onshore, OCS, or Indian lease, or federally-approved agreement before the point of final royalty determination for 6 months; and
(2) You notified MMS in writing within 30 days after the end of the 6-month period.
(f) You must file a Form MMS-4056 when your plant resumes processing gas that originated from a Federal onshore, OCS, or Indian lease, or federally-approved agreement before the point of final royalty determination.
(a) Any operator of an offshore Facility Measurement Point (FMP) handling production from a Federal lease or federally-approved agreement that is commingled (with approval) with production from any other source prior to measurement for royalty determination must file a Production Allocation Schedule Report (Form MMS-4058). This report is not required whenever all of the following conditions are met:
(1) All leases involved are Federal leases;
(2) All leases have the same fixed royalty rate;
(3) All leases are operated by the same operator;
(4) The facility measurement device is operated by the same person as the leases/agreements;
(5) Production has not been previously measured for royalty determination; and
(6) The production is not subsequently commingled and measured for royalty determination at an FMP for which Form MMS-4058 is required under this part.
(b) You must submit a Production Allocation Schedule Report, Form
(c) MMS must receive your Form MMS-4058 according to the following table:
In accordance with its regulations at 43 CFR 3103.4-1, titled “Waiver, suspension, or reduction of rental, royalty, or minimum royalty,” the Bureau of Land Management (BLM) may grant reduced royalty rates to operators of low producing oil leases to encourage continued production. Operators who have been granted a reduced royalty rate(s) by BLM must submit a Stripper Royalty Rate Reduction Notification (Form MMS-4377) to MMS for each 12-month qualifying period that a reduced royalty rate(s) is granted.
The Mine Information Form (Form MMS-4050) must be filed for each mine that includes Federal or Indian leases in its approved mining plan. The completed form must be filed by the operator of the mine/lease(s). Form MMS-4050 must be filed at the request of the MMS initially during the conversion of the mine/lease(s) to the PAAS.
The Facility and Measurement Information Form (Form MMS-4051) must be filed for each facility or measurement device which handles solid mineral production from any Federal or Indian lease, or federally approved agreement, through the point of first sale or the point of royalty computation, whichever is applicable. The completed form must be filed by the operator of the facility or measurement device. Form MMS-4051 must be filed initially at the request of the MMS during the conversion of facility and measurement device operators to the PAAS. Subsequent to conversion, Form MMS-4051 must be filed with MMS/RMP no later than 30 days after establishment of a new facility or measurement device, or a change to any existing facility or measurement device that handles production attributable to any Federal or Indian lease, or federally approved agreement, through the point of first sale or royalty computation, whichever is applicable.
The Solid Minerals Operation Report (Form MMS-4059) must be submitted by all Federal and Indian lease operators of producing mines that are part of an approved mine plan. Form MMS-4059 must be filed for the same period established for payment for royalties in the lease terms, unless a different reporting frequency is established by an MMS authorized official, and on or before the 15th day of the second month following the period being reported until all the leases within a mine are terminated or until omission of the report is authorized by the MMS.
The Solid Minerals Facility Report (Form MMS-4060) must be filed by operators of secondary processing facilities that handle production attributable to Federal or Indian leases where royalty is determined after processing. The report period is monthly, unless a longer period is specified in the lease document, or otherwise approved by the MMS. The Form MMS-
35 Stat. 312; 35 Stat. 781, as amended; secs. 32, 6, 26, 41 Stat. 450, 753, 1248; secs. 1, 2, 3, 44 Stat. 301, as amended; secs. 6, 3, 44 Stat. 659, 710; secs. 1, 2, 3, 44 Stat. 1057; 47 Stat. 1487; 49 Stat. 1482, 1250, 1967, 2026; 52 Stat. 347; sec. 10, 53 Stat. 1196, as amended; 56 Stat. 273; sec. 10, 61 Stat. 915; sec. 3, 63 Stat. 683; 64 Stat. 311; 25 U.S.C. 396, 396a-f, 30 U.S.C. 189, 271, 281, 293, 359. Interpret or apply secs. 5, 5, 44 Stat. 302, 1058, as amended; 58 Stat. 483-485; 5 U.S.C. 301, 16 U.S.C. 508b, 30 U.S.C. 189, 192c, 271, 281, 293, 359, 43 U.S.C. 387, unless otherwise noted.
The Federal Oil and Gas Royalty Management Act of 1982 (30 U.S.C. 1701
The Secretary, or his/her authorized representative, shall initiate and conduct audits relating to the scope, nature and extent of compliance by lessees, operators, revenue payors, and other persons with rental, royalty, net profit share and other payment requirements on a Federal or Indian oil and gas lease. Audits also will relate to compliance with applicable regulations and orders. All audits will be conducted in accordance with the notice and other requirements of 30 U.S.C. 1717.
Specific lease account reconciliations shall be performed with priority being given to reconciling those lease accounts specifically identified by a State or Indian tribe as having significant potential for underpayment.
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
An audit of the accounts and books of operators/lessees for the purpose of determining compliance with Federal lease terms relating to Federal royalties may be required annually or at other times as directed by the Associate Director for Royalty Management. The audit shall be performed by a qualified independent certified public accountant or by an independent public accountant licensed by a State, territory, or insular possession of the
An audit of the lessee's accounts and books may be made annually or at such other times as may be directed by the mining supervisor, by certified public accountants, and at the expense of the lessee. The lessee shall furnish free of cost duplicate copies of such annual or other audits to the mining supervisor, within 30 days after the completion of each auditing.
25 U.S.C. 396
The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501
(a) An assessment of an amount not to exceed $10 per day may be charged for each report not received by MMS by the designated due date.
(b) An assessment of an amount not to exceed $10 may be charged for each incorrectly completed report.
(c) For purposes of reports required for the Auditing and Financial System (AFS), a report is defined as each line item on a Form MMS-2014. The line item consists of the various information, such as Product Code or Selling Arrangement Code, relating to each Accounting Identification Number (AID).
(d) An assessment under this section shall not be shared with a State, Indian tribe, or Indian allottee.
(e) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by MMS. The assessment amount for each violation will be based on MMS's experience with costs and improper reporting. The MMS will publish a Notice of the assessment amount to be applied in the
(a) An assessment of an amount not to exceed $250 may be charged when the amount of a payment submitted by a payor is not equivalent in amount to the total of individual line items on the associated Form MMS 2014 or bill document, unless the difference in amount has been authorized by MMS.
(b) An assessment of an amount not to exceed $250 may be charged for each payment submitted by a payor that cannot be automatically applied by AFS to the associated Form MMS-2014 or bill document because of inadequate or erroneous information submitted by the payor. For purposes of this section, inadequate or erroneous information is defined as:
(1) Absent or incorrect payor assigned document number, required to be identified by the payor in Block 3a on a Form MMS-2014, or the reuse of the same payor assigned document (“3a”) number in a subsequent reporting period.
(2) Absent or incorrect bill document invoice number (to include the four character alpha prefix and the eight digit number) or the payor-assigned 3a number required to be identified by the payor on the associated payment document, or the reuse of the same payor assigned 3a number in a subsequent reporting period.
(3) Absent or incorrect name of the administering Bureau of Indian Affairs Agency/Area office and the word “allotted” or the tribe name on payment documents remitted to MMS for an Indian tribe or allottee. If the payment is made by EFT, the payor must identify the tribe/allottee on the EFT message by a pre-established five digit code.
(4) Absent or incorrect MMS assigned payor code on a payment document.
(c) For purposes of this section, the term “Form MMS-2014” includes submission of reports of royalty information by magnetic media. Magnetic media submissions include submissions by magnetic tape, magnetic cartridge, or floppy diskette.
(d) For purposes of this section, a bill document is defined as any Bill of Collection (Form DI-1040b) that has been issued by MMS for assessments, late-payment interest charges, or other amounts owed.
(e) For purposes of this section, a payment document is defined as one of the payment methods identified in § 218.51(a)(3).
(f) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by MMS. The assessment amount will be based on MMS’ experience with costs and improper reporting and/or payment as specified in this section. The MMS will
(a) Interest due from a payor on any underpayment for any Federal mineral lease or leases (onshore or offshore) and on any Indian tribal mineral lease or leases for any production month shall not be reduced by offsetting against that underpayment any overpayment made by the payor on any other lease or leases, except as provided in paragraph (b) of this section. Interest due from a payor or any underpayment on any Indian allotted lease shall not be reduced by offsetting against any overpayment on any other Indian allotted lease under any circumstances.
(b) Royalties attributed to production from a lease or leases which should have been attributed to production from a different lease or leases may be offset to determine whether and to what extent an underpayment exists on which interest is due if the following conditions are met:
(1) The error results from attributing and reporting an equal volume of production, produced from a lease or leases during a particular production month, to a different lease or leases from which it was not produced for the same or another production month;
(2) The payor is the same for the lease or leases to which production was attributed and the lease or leases to which it should have been attributed;
(3) The payor submits production reports, pipeline allocation reports, or other similar documentary evidence pertaining to the specific production involved which verifies the correct production information;
(4) The lessor is the same for the leases involved (in the case of Indian tribal leases, the same tribe is the lessor); and
(5) The ultimate recipients of any royalty or other lease revenues under any applicable permanent indefinite appropriations are the same for, and receive the same percentage of revenue from, the leases.
(c) If MMS assesses late-payment interest and the payor asserts that some or all of the interest assessed is not owed pursuant to the exception set forth in paragraph (b) of this section, the burden is on the payor to demonstrate that the exception applies in the specific circumstances of the case.
(d) The exception set forth in paragraph (b) of this section shall not operate to relieve any payor of liability imposed by statute or regulation for erroneous reporting.
(a) Royalty payments are due at the end of the month following the month during which the oil and gas is produced and sold except when the last day of the month falls on a weekend or holiday. In such cases, payments are due on the first business day of the succeeding month. Rental payments are due as specified by the lease terms.
(b) Payments made on a Bill for Collection (Form DI-1040b) are due as specified by the Bill. Bills for Collection will be issued and payable as final collection actions.
(c) All payments to MMS are due as specified and are not deferred or suspended by reason of an appeal having been filed unless such deferral or suspension is approved in writing by an authorized MMS official.
(a)
(b)
(1) If MMS instructs you to use EFT, you must use EFT for all payments to MMS and/or a tribe.
(2) Contact MMS before using EFT. MMS will provide you with EFT payment instructions.
(3) Separate any payments on a Federal lease from any payments on an Indian lease.
(4) If you are not required to use EFT, use one of the following types of payment documents. MMS prefers that you use these payment documents in the order presented:
(i) Commercial check drawn on a solvent bank;
(ii) Certified check;
(iii) Cashier's check;
(iv) Money order;
(v) Bank draft drawn on a solvent bank; or
(vi) Federal Reserve check.
(5) You must include your payor code on all payments.
(6) You must pay in U.S. dollars.
(c)
(2) For an Indian allottee payment, send a separate payment for each Bureau of Indian Affairs (BIA) agency or area office represented by the leases on your report or invoice document. You must include the name of the applicable BIA agency or area office on your payment. Make your payment document payable to: “Department of the Interior-Minerals Management Service for BIA [Name] Agency (allotted)” or “DOI-MMS for BIA [Name] Agency (allotted).”
(3) For an Indian tribal payment other than a lockbox payment, send a separate payment for each tribe represented by the leases on your report or invoice document. You must include the name of the Indian tribe on your payment. Make it payable to: “Department of the Interior-Minerals Management Service for BIA [Name of Tribe]” or “DOI-MMS for BIA [Name of Tribe].”
(4) For an Indian tribal lockbox payment, follow the instructions MMS provides you on how to report and make the lockbox payment. These instructions are specific to each tribe's lockbox written agreement with the bank authorized to receive payments on the tribe's mineral leases. You will receive these instructions from MMS when you are required to use a tribal lockbox for reports and payments.
(d)
(2) For a Federal nonproducing lease rental or deferred bonus payment, send it to:
Minerals Management Service, Royalty Management Program, P.O. Box 5640, Denver, CO 80217-5640.
(3) For all other Federal and Indian lease payments other than those going to an Indian tribal lockbox, send them to:
Minerals Management Service, Royalty Management Program, P.O. Box 5810, Denver, CO 80217-5810.
(e)
Minerals Management Service, Royalty Management Program, Building 85, Denver Federal Center, Room A-212, Denver, CO 80225-0165.
(f)
(2) For invoice payments, including RIK invoice payments, you must include both your payor code and invoice document identification (four-letter prefix and eight-digit number).
(3) For bonus payments:
(i) For one-fifth bonus payments for offshore oil, gas, and sulphur leases, follow the instructions in the Notice of Lease Offering.
(ii) For payment of the four-fifths bonus for an offshore lease, use EFT and follow the instructions in § 218.155(c).
(iii) For the successful bidder's bonus in the competitive sale of a coal, geothermal, or offshore mineral (other than oil, gas or sulfur) lease, follow the instructions and terms of the Notice of Competitive Lease Sale.
(iv) For installment payments of deferred bonuses, you must use EFT.
(4) If you are paying a lease rental you must:
(i) See 30 CFR 218.155(c) for instructions on how to pay first-year rentals of an offshore oil, gas, or sulfur lease;
(ii) See the Notice of Lease Offering for instructions on how to pay first-year rentals other than those covered in paragraph (f)(4)(i) of this section.
(iii) Include the MMS Courtesy Notice, when provided, or write your payor code and government-assigned lease number on the payment document when paying a rental that is not reported on Form MMS-2014 and not paid by EFT.
(g)
(2) If you use the U.S. Postal Service, courier, or overnight mail to send your payment, it is due at the MMS addresses in paragraphs (d) and (e) of this section before 4 p.m. Mountain Time on the due date, regardless of when you sent it.
(3) If you use EFT to send your payment, it is due in the MMS account by the payment due date. You are responsible for your actions or your bank's actions that cause a late or incorrect payment. You will not be held responsible for mechanical or system failures of EFT payments.
(h)
(1) If MMS receives your payment late, MMS will impose a late-payment interest charge under 30 CFR 218.54.
(2) If you do not pay an amount you owe, MMS may assess civil penalties under 30 CFR 241.20 and 241.51 or other applicable regulations.
(a) If you are a lessee under 30 U.S.C. 1701(7), and you want to designate a person to make all or part of the payments due under a lease on your behalf under 30 U.S.C. 1712(a), you must notify MMS or the applicable delegated State in writing of such designation. Your notification for each lease must include the following:
(1) The AID number for the lease;
(2) The type of products you make payments for e.g., oil, gas.
(3) The type of payments you are responsible for e.g., royalty, minimum royalty, rental.
(4) Whether you are:
(i) A lessee of record (record title owner) in the lease, and the percentage of your record title ownership in the lease; or
(ii) An operating rights owner (working interest owner) in the lease, and the percentage of your operating rights ownership in the lease;
(5) The name, address, Taxpayer Identification Number (TIN), and phone number of your Designee;
(6) The name, address, and phone number of the individual to contact for the person you named in paragraph (a)(5) of this section;
(7) Your TIN;
(8) The date the designation is effective;
(9) The date the designation terminates, if applicable, and
(10) A copy of the written designation;
(b) The person you designate under paragraph (a) of this section is your Designee under 30 U.S.C. 1701(24) and 30 U.S.C. 1712(a).
(c) If you want to terminate a designation you made under paragraph (a) of this section, you must provide to MMS in writing before the termination:
(1) The date the designation is due to terminate; and
(2) If you are not reporting and paying royalties and making other payments to MMS, a new designation under paragraph (a) of this section.
(d) MMS may require you to provide notice when there is a change in the percentage of your record title or operating rights ownership.
(a) Whenever an overpayment is made under an Indian oil and gas lease, a payor may recoup the overpayment through a recoupment on Form MMS-2014 against the current month's royalties or other revenues owed on the same lease. However, for any month a payor may not recoup more than 50 percent of the royalties or other revenues owed in that month under an individual allotted lease or more than 100 percent of the royalties or other revenues owed in that month under a tribal lease.
(b) With written permission authorized by tribal statute or resolution, a payor may recoup an overpayment against royalties or other revenues owed in that month under other leases for which that tribe is the lessor. A copy of the tribe's written permission must be furnished to MMS pursuant to instructions for reporting recoupments in the MMS “Oil and Gas Payor Handbook.” See 30 CFR 210.53. Recouping overpayments on one allotted lease from royalties paid to another allotted lease is specifically prohibited.
(c) Overpayments subject to recoupment under this section include all payments made in excess of the required payment for royalty, rental, bonus, or other amounts owed as specified by statute, regulation, order, or terms of an Indian mineral lease.
(d) The MMS Director or his/her designee may order any payor to not recoup any amount for such reasonable period of time as may be necessary for MMS to review the nature and amount of any claimed overpayment.
(a) An interest charge shall be assessed on unpaid and underpaid amounts from the date the amounts are due.
(b) The interest charge on late payments shall be at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).
(c) Interest will be charged only on the amount of the payment not received. Interest will be charged only for the number of days the payment is late.
(d) A portion of the interest collected will be paid to a State where the State shares in mineral revenues from Federal leases.
(e) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
(a) All interest collected from unpaid or underpayments on Indian tribal or allotted leases will be paid to the tribe or allottee.
(b) Any disbursement of Indian mineral revenues not made by the due date as required in § 219.103 of this chapter shall accrue interest.
(c) Interest shall be computed at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).
(d) The interest shall be payable only for the number of days the disbursement is late.
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
(a)
(2) If a person has any information he or she believes would be valuable to MMS, that person (“informant”) should submit the information in writing, in the form of a letter, mailed or delivered in person to the Director, Minerals Management Service, Department of the Interior, 18th and C Street, NW., Washington, DC 20240, or to the Director's designated representative. Although written communications are preferred, oral information will be accepted.
(3) The informant should provide all data he or she has with respect to royalty or other payments owed. The information provided should include: identification of the alleged debtor; the source of the informant's knowledge of royalties or other payments owed; the date, if known, of the indebtedness; and any other information that could be used to establish indebtedness. All information received by MMS from persons providing information will be considered “highly confidential” and will not be disclosed to any individual except on a “need to know” basis in the performance of official duties.
(b)
(2) A claim for reward is not acceptable if filed on behalf of a claimant by his or her agent under power of attorney. However, an agent may provide MMS with information for an unidentified informant, to be evaluated and used by MMS as it deems appropriate. The informant's identity ultimately must be disclosed if the informant intends to file a claim for reward so that MMS can report the reward as taxable income to the Internal Revenue Service. An executor, administrator, or other legal representative of a deceased informant may file a claim on behalf of such deceased informant if, prior to his or her death, the informant was eligible to file a claim under this section. The representative must attach to the claim evidence of authority to file it.
(3) To file a claim for reward the informant must:
(i) Notify the Director, MMS, or the person to whom the information was reported, that he/she is claiming a reward.
(ii) Request an “Application for Reward for Original Information” (Form MMS-4280). This form provides for information to enable MMS to determine and pay rewards, to control reward applications, and to report a claimant's reward as taxable income to the Internal Revenue Service.
(iii) File a claim for reward by completing Form MMS-4280, sign it with his or her true name, and mail or deliver it in person to the Director or to the Director's designated representative. If the informant provided the information in person, the claim should include the name and title of the person to whom the information was reported and the date that it was reported.
(4) If the informant used an identity other than his or true name when the
(c)
(1) Where the information originally furnished was deemed unworthy of initiating an investigation, but at some later date the records of the lessee are examined without reference to the information furnished. The claim will be rejected on the basis that the information did not cause the investigation nor did it, in itself, result in any recovery.
(2) For information that would have been discovered during the normal course of an audit or investigation.
(3) Unless the informant's true identity is disclosed.
(4) Until after all of the royalties, penalties, or other payments discovered to be owed as a result of information provided are collected and no longer subject to dispute.
(5) Unless funds are appropriated for the payment of rewards.
(d)
(2) In determining whether a reward will be allowed and, if so, the amount thereof, consideration will be given to any corresponding adjustment(s) which will result in potential savings to the lessee for other leases owned by the lessee or an affiliate of the lessee. An example of such an adjustment is a reduction in royalty payment on a different lease as the result of a revised allocation under a unitization or communitization agreement or from an offshore pipeline system. Rewards otherwise allowable will be reduced or rejected by reason of such offsetting adjustments.
(3) If several claims filed by one informant are considered in one recommendation, the reward, if any, may be allowed on one claim and the others may be closed by reference.
(4) Where an informant has provided information and filed a claim for reward with respect to royalty reports of one lessee for several leases, no reward will be granted with respect to an individual lease which has been examined until examination of all leases involved has been completed. Because the possibility exists that adjustments made to the reports for the open leases may result in offsetting adjustments, no reward will be allowed until the overall results of the information are evaluated.
(e)
(i) For specific and responsible information that caused the investigation and resulted in recovery, the reward will be 10 percent of the first $75,000 recovered, 5 percent of the next $25,000, and 1 percent of any additional recovery. The total reward cannot exceed $100,000.
(ii) For information that caused the examination and was of value in determining royalty or other payments due, although not specific, and for information that was a direct factor in recovering royalty or other payments, the reward will be 5 percent of the first $75,000 recovered, 2
(iii) For information that caused the investigation but was of no value in determining royalty or other payments due, the reward will be 1 percent of the first $75,000 recovered and
(2) Rewards will be paid only if moneys are appropriated for that purpose. Subject to appropriations, payments will be made as soon as possible after collection of the amounts owed by the lessee, and after those amounts no longer are subject to dispute by the payor. The reward payment to an informant will be net of Federal and State income tax in accordance with withholding guidelines of the Internal Revenue Service and the applicable State(s).
(3) A decision by the Director, MMS, either denying a reward or establishing the amount of any reward is a final departmental action and may not be appealed to the Interior Board of Land Appeals in accordance with the provisions of 30 CFR part 290.
(a)
(b) If the lessor elects to take royalty in oil or gas, unless otherwise agreed upon, such royalty shall be delivered on the leasehold, by the lessee to the order of and without cost to the lessor, as instructed by the Associate Director.
(c)
Remittance covering payments of royalty or rental on naval petroleum reserves must be accomplished by necessary identification information and sent direct to the Director, Naval Petroleum Reserves in California.
(a) The failure to make timely or proper payments of any monies due pursuant to leases, permits, and contracts subject to these regulations will result in the collection by the MMS of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the payor. However, late payment charges assessed with respect to any Indian lease, permit, or contract shall be collected and paid to the Indian or tribe to which the amount overdue is owed.
(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51(f)(1) and (f)(2). Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.
(c) Late payment charges apply to all underpayments and payments received after the date due. The charges include production and minimum royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/permittee/payor/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due amounts, including late-payment charges, will result in the initiation of other enforcement proceedings.
(d) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on
(a) Any amount that is payable by MMS to a State but is not paid on the due date, as specified in § 219.100 of this chapter, or that is held in a suspense account pending resolution of a dispute as specified in § 219.101 of this chapter, shall accrue interest payable to the State.
(b) Interest shall be computed at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).
(c) Interest shall be computed only for the number of days the disbursement is late. In the case of suspended amounts subject to interest, it shall be computed beginning with the calendar day following the day that the monies normally would have been paid to the State had they not been in suspense.
(a) States are exempt from being assessed for any interest or penalties found to be due against the Department of the Interior for failure to comply with the Emergency Petroleum Allocation Act of 1973, as amended, or any regulation issued by the Secretary of Energy thereunder concerning the certification or processing of crude oil taken in-kind as royalty by the Secretary.
(b) Any State shall be assessed for its share of any overcharge resulting from a determination that DOI failed to comply with the Emergency Petroleum Allocation Act of 1973, as amended. Each State's share shall be assessed against monies owed to the State. Such assessment shall be first against monies owed to such State as a result of royalty audits prior to January 12, 1983, the enactment date of the Federal Oil and Gas Royalty Management Act of 1982, then against other monies owed. The State shall be liable for any balance.
(c) A State's liability for repayment of an overcharge under this section shall exist for any amounts resulting from a judgment in a civil suit or as the result of settlement of a claim through a negotiated agreement. State liability would be offset against future mineral revenue distributions to the State.
Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.
(a) As specified under the provisions of the lease, the lessee shall submit all rental payments when due and shall pay in value or deliver in production all royalties and net profit shares in the amounts of value or production determined by MMS to be due.
(b) The failure to make timely or proper payments of any monies due pursuant to leases, permits, and contracts subject to these regulations will result in the collection of the amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the payor.
(c) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51(f)(1) and (f)(2). Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.
(d) Late payment charges apply to all underpayments and payments received after the date due. These charges include production and minimum royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind;
(e) An overpayment on a lease or leases, excluding rental payments, may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
(a) Except for leases issued subject to net profit sharing provisions, an annual rental shall be due and payable in advance, at the rate specified in the oil and gas leases, on the first day of each lease year prior to discovery of oil or gas on the lease.
(b) The owner of any lease created by the segregation of a portion of a producing lease which is not subject to net profit sharing provisions and on which segregated portion there is no production, actual or allocated, shall pay an annual rental for such segregated portion at the rate per acre or hectare specified in the lease. This rental shall be payable each lease year following the year in which the segregation became effective and prior to a discovery on such segregated portion.
(c) Annual rental paid in any year shall be in addition to, and shall not be credited against, any royalties due from production.
(d) An annual rental on a lease for a mineral other than oil or gas, shall be due and payable, in advance, on the first day of each lease year prior to discovery in paying quantities, at a rate specified in the lease form.
(e) For leases issued subject to the net profit sharing provisions, annual rental payments shall be due and payable in advance, on the first day of each lease year which commences prior to the date the first profit share payment becomes due. The owner of any lease created by the segreation of a portion of a lease subject to net profit sharing provisions, shall pay an annual rental for such segregated portion at the rate per acre or hectare specified in the lease. This rental shall be payable each year following the year in which the segregation becomes effective and shall continue to be due and payable, in advance, on the first day of each year which commences prior to the date the first profit share payment becomes due.
Upon the establishment of the Fishermen's Contingency Fund, any holder of a lease issued or maintained under the Outer Continental Shelf Lands Act and any holder of an exploration permit or of an easement or right-of-way for the construction of a pipeline, shall pay an amount specified by the Director, MMS, who shall assess and collect the specified amount from each holder and deposit it into the Fund. With respect to prelease exploratory drilling permits, the amount will be collected at the time of issuance of the permit.
(a) MMS will not relieve the lessee of the obligation to pay rental or minimum royalty for or during the suspension if the Regional Supervisor:
(1) Grants a suspension of operations or production, or both, at the request of the lessee; or
(2) Directs a suspension of operations or production, or both, under 30 CFR 250.173(a).
(b) MMS will not require a lessee to pay rental or minimum royalty for or during the suspension if the Regional Supervisor directs a suspension of operations or production, or both, except as provided in (a)(2) of this section.
(c) If the lease anniversary date falls within a period of suspension for which no rental or minimum royalty payments are required under paragraph (a)
(a)
(b)
(2) Beginning with lease offerings held after February 1, 1984, the one-fifth bonus amount received from a high bidder shall be deposited into an escrow account created pursuant to an agreement between the Departments of the Interior and Treasury, pending acceptance or rejection of the bid. The one-fifth bonus funds will be invested in public debt securities. Investment of this amount by the U.S. Government does not indicate acceptance of the bid. The one-fifth bonus checks submitted with bids other than the highest valid bid shall be returned to respective bidders after bids are opened, recorded, and ranked. Return of such checks will not affect the status, validity, or ranking of bids. The one-fifth bonus bid amount received from any high bidder and held by the Government pending acceptance or rejection, will be returned with actual interest earned, if the bid is subsequently rejected. The interest accrued during the period held in the account pending acceptance or rejection of the bid will accrue to the Government when the bid is accepted.
(c)
(d)
(2) Where to pay.
(3) The MMS mailing addresses for payments to MMS are specified in § 218.51 (f)(1) and (f)(2).
(4) Payments received at the MMS addresses after 4 p.m. mountain time
(e)
(1) Pipeline rights-of-way application filing fees and rentals, pipeline accessory site rentals and application fees, and other related costs.
(2) Filing and approval fees for transfers of interest in leases.
Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.
As specified under the provisions of the lease, the lessee shall submit all rental and deferred bonus payments when due and shall pay in value all royalties in the amount determined by MMS to be due.
The payor shall tender all payments in accordance with 30 CFR 218.51.
(a) The failure to make timely or proper payment of any monies due pursuant to leases and contracts subject to these rules will result in the collection by MMS of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the operator/lessee. However, late payment charges assessed with respect to any Indian lease, permit, or contract shall be collected and paid to the Indian or tribe to which the amount overdue is owed.
(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in 218.51(f)(1) and (f)(2). Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.
(c) The interest charge on late payments shall be at the underpayment rate established by section 6621(a)(2) of the Internal Revenue Code, 26 U.S.C. 6621(a)(2).
(d) Interest will be charged only on the amount of the payment not received by the designated due date. Interest will be charged only for the number of days the payment is late.
(e) Late payment charges apply to all underpayments and payments received after the date due. These charges include production, minimum, or advance royalties; assessments for liquidated damages; or any other payments, fees, or assessments that an operator/lessee is required to pay by a specified date. The failure to pay past due payments, including late payment charges, will result in the initiation of other enforcement proceedings.
(f) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
(a) Whenever an overpayment is made under an Indian solid mineral lease, a payor may recoup the overpayment through a recoupment on Form MMS-2014 against the current month's royalties or other revenues owed on the same lease. However, for any month a payor may not recoup more than 50
(b) With written permission authorized by tribal statute or resolution, a payor may recoup an overpayment against royalties or other revenues owed in that month under other leases for which that tribe is the lessor. A copy of the tribe's written permission must be furnished to MMS pursuant to instructions for reporting recoupments in the “AFS Payor Handbook—Solid Minerals.” See 30 CFR 210.204. Recouping overpayments on one allotted lease from royalties paid to another allotted lease is specifically prohibited.
(c) Overpayments subject to recoupment under this section include all payments made in excess of the required payment for royalty, rental, bonus, or other amounts owed as specified by statute, regulation, order, or terms of an Indian mineral lease.
(d) The MMS Director or his/her designee may order any payor to not recoup any amount for such reasonable period of time as may be necessary for MMS to review the nature and amount of any claimed overpayment.
As specified under the provisions of the lease, the lessee shall submit all rental and deferred bonus payments when due and shall pay in value all royalties in the amount determined by MMS to be due.
The payor shall tender all payments in accordance with 30 CFR 218.51.
(a) The failure to make timely or proper payment of any monies due pursuant to leases and contracts subject to these regulations will result in the collection by the Minerals Management Service (MMS) of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with the instructions provided by the MMS to the payor.
(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51 (f)(1) and (f)(2). Payments received at the specified MMS addresses after 4 p.m. Mountain Time are considered received the following business day.
(c) The interest charge on late payments shall be at the underpayment rate established by section 6621(a)(2) of the Internal Revenue Code, 26 U.S.C. 6621(a)(2).
(d) Interest will be charged only on the amount of the payment not received by the designated due date. Interest will be charged only for the number of days the payment is late.
(e) Late payment charges apply to all underpayments and payments received after the date due. These charges include production, minimum, and compensatory royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/payor/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due payments, including late payment charges, will result in the initiation of other enforcement proceedings.
(f) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.
Section 104, Pub. L. 97-451, 96 Stat. 2451 (30 U.S.C. 1714).
A State's share of mineral leasing revenues shall be paid to the State not later than the last business day of the month in which the U.S. Treasury issues a warrant authorizing the disbursement, except for any portion of such revenues which is under challenge and placed in a suspense account pending resolution of a dispute.
(a) Subject to the availability of appropriations, the Minerals Management Service (MMS) shall pay the State its proportionate share of any interest charge for royalty and related monies that are placed in a suspense account pending resolution of matters which will allow distribution and disbursement. Such monies not disbursed by the last business day of the month following receipt by MMS shall accrue interest until paid.
(b) Upon resolution, the suspended monies found due in paragraph (a) of this section, plus interest, shall be disbursed to the State under the provisions of § 219.100.
(c) Paragraph (a) of this section shall apply to revenues which cannot be disbursed to the State because the payor/lessee provided incorrect, inadequate, or incomplete information to MMS which prevented MMS from properly identifying the payment to the proper recipient.
The MMS shall disburse monies to a State either by Treasury check or by Electronic Funds Transfer (EFT). Should a State prefer to receive its payment by EFT, it should request this payment method in writing to the Minerals Management Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado 80217-5760.
Mineral revenues received from Indian leases shall be transferred to the appropriate Indian accounts managed by the Bureau of Indian Affairs (BIA) for allotted and tribal revenues. These accounts are specifically designated Treasury accounts. Revenues shall be transferred to the Indian accounts at the earliest practicable date after such funds are received, but in no case later than the last business day of the month in which revenues are received by the MMS.
(a) Payments to States and BIA on behalf of Indian tribes or Indian allottees discussed in this part shall be described in
(b) The report shall be provided to: (1) States not later than the 10th day of the month following the month in which MMS disburses the State's share of royalties and related monies; (2) the BIA on behalf of tribes and Indian allottees not later than the 10th day of the month following the month the funds are disbursed by MMS.
(c) Revenues that cannot be distributed to States, tribes, or Indian allottees because the payor/lessee provided incorrect, inadequate, or incomplete information, preventing MMS from properly identifying the payment to the proper recipient, shall not be included in the reports until the problem is resolved.
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
Sec. 205, Pub. L. 95-372, 92 Stat. 643 (43 U.S.C. 1337).
(a) This part 220 establishes accounting procedures for determining the net profit share base and calculating net profit share payments due the United States for the production of oil and gas from OCS leases.
(b) The procedures established by this part 220 apply to any OCS lease issued by the Department of the Interior under any bidding system established by § 260.110(a) of this chapter which has a net profit share component.
For purposes of this part 220:
(1) The lessee completes the last well on the first platform specified in the development and production plan originally approved by the MMS, with any approved amendments thereto, and installation of wellhead equipment. In the event the last well is dry, then the capital recovery period shall be deemed to have ended with the determination that the last well is non-productive;
(2) The balance in the NPSL capital account changes from a debit balance to a credit balance; or
(3) The lessee, at his election, chooses to terminate the capital recovery period. A decision to terminate the capital recovery period prior to the events specified in paragraphs (a) (1) and (2) of this definition shall be communicated in writing to the Director and shall be irrevocable.
(1) Shore base support facilities,
(2) Shore base production facilities, e.g., pumps, separating facilities, gas plants, and tankage for production from the NPSL tract.
(a) The information collection requirements of this part have been approved by OMB under 44 U.S.C. 3501 et seq. and assigned OMB Clearance Number 1010-0073. The information will be used to determine all allowable direct and allocable joint costs incurred during the term of the lease, appropriate overhead allowances permitted on these costs pursuant to § 220.012, and allowances for capital recovery calculated pursuant to § 220.020. The information collection is mandatory in accordance with the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 et seq.
(b) Public reporting burden is estimated to average 16 hours for each annual and monthly lease report, including time spent reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding the burden estimate or any other aspect of this collection of information, including suggestions for reducing burden, to the Information Collection Clearance Officer, Minerals Management Service, 281 Elden Street, Herndon, Virginia 22070; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Paperwork Reduction Project 1010-0073, Washington, DC 20503.
(a) For each NPSL tract, an NPSL capital account shall be established and maintained by the lessee for NPSL operations. The NPSL capital account shall include debit entries for all allowable direct and allocable joint costs incurred during the term of the lease, appropriate overhead allowances permitted on these costs pursuant to § 220.012, and allowances for capital recovery calculated pursuant to § 220.020. The NPSL capital account shall be credited with production revenues attributable to the NPSL and any other credits arising from NPSL activities.
(b) The NPSL capital account shall be kept on an accrual basis.
The costs and credits specified in paragraphs (a) through (p) of this section may be charged direct, or allocated to NPSL operations, as appropriate, in accordance with § 220.014.
(a)
(b)
(ii) Salaries and wages of technical employees within technical branches of the lessee's organization who are either temporarily or permanently assigned to, and directly employed in NPSL operations are allowable provided that such employees work “full time” on some particular aspect of NPSL operations or some specific technical problem. Excluded from this category are employees assigned a role in NPSL operations as a duty collateral with other duties that do not directly benefit NPSL operations.
(iii) Salaries and wages of technical employees within technical branches of the lessee's organization who are assigned technical tasks directly related to NPSL operations may be allowable. Costs may be charged to the NPSL if supported by adequate time records showing the nature of the task and the hours spent on that task.
(2) Lessee's cost of allowed employee absence paid to employees whose salaries and wages are chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) of this section are allowable.
(3) Expenditures or contributions made pursuant to assessments imposed by governmental authority that are applicable to lessee's costs chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section are allowable.
(4) Reasonable personal expenses, including allowable relocation costs of employees whose salaries and wages are chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) of this section and that are paid by the lessee or for which the employees are reimbursed under the lessee's normal practice are allowable except as limited by § 220.013(g).
(i) Allowable relocation costs include:
(A) Travel expenses, including transportation, lodging, subsistence, and reasonable incidental expenses of the employee and members of his immediate family and transportation of his household and personal effects to the new location.
(B) Other necessary and reasonable expenses normally incident to relocation, such as costs of cancelling an unexpired lease, disconnecting and reinstalling household applicances, and purchases of insurance against damages to or loss of personal property are allowable. Costs of cancelling an unexpired lease shall not exceed three times the monthly rental.
(C) Closing costs (i.e. brokerage fees, legal fees, appraisal fees, etc.) for the sale of the employee's actual residence when notified of the transfer are allowable; and
(D) Continuing costs of ownership of the vacant former actual residence being sold, such as continuing mortgage principal and interest payments, maintenance of building and grounds (exclusive of fixing-up expenses), utilities, taxes, property insurance, etc., after settlement date of lease or date of new permanent residence are allowable.
(ii) The combined total of costs listed in paragraphs (b)(4)(i) (C) through (D) of this section shall not exceed 8 percent of the sales price of the property sold.
(iii) Section 220.013(g) specifies employee relocation expenses that are not allowable as a charge to NPSL operations.
(5) Lessee's current costs of established plans for employee's group life insurance, hospitalization, pension, retirement, stock purchase, thrift, bonds, and other benefit plans of a like nature that are made available to all of lessee's employees on an equitable basis, applicable to lessee's labor cost chargeable to NPSL operations under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section, are allowable. The amount of these charges shall be lessee's actual cost not to exceed 23 percent of the
(6) Charges for expenses incurred under paragraphs (b)(2) through (b)(5) of this section may be made to NPSL accounts on a “when and as paid” basis or by a percentage assessment method. If the percentage assessment method is used, it shall be based upon the lessee's actual cost experience expressed as a percentage of costs chargeable under paragraphs (b)(1) (i) and (ii) and (b)(2) of this section. Under either method the lessee's own cost of administering the plans and paying the salaries and benefits defined in this paragraph shall be excluded. In determining actual cost experience of an employee benefit plan, any dividend or refunds received that are applicable to insurance or annuity policies shall be used to reduce the cost of such policies.
(c)
(2) Charges to an NPSL account shall be made only for such materiel purchased or furnished as NPSL property as is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided.
(3) Credit for salvaged or returned materiel shall be made to the NPSL capital account. When the amount originally charged qualifies for the allowance for capital recovery in § 220.020, the credit shall be calculated pursuant to § 220.021(a)(3).
(d)
(1) If materiel is moved to the NPSL project area, no charge shall be made to NPSL operations for a distance greater than the distance from the nearest reliable supply store, recognized barge terminal, or railway receiving point where like materiel is normally available, unless agreed to by the Director.
(2) If surplus materiel is moved from the NPSL project area, no charge shall be made to NPSL operations for a distance greater than the distance to the nearest reliable supply store, recognized barge terminal, or railway receiving point unless agreed to by the Director. No charge shall be made to NPSL operations for moving materiel to other properties owned by or under the control of a lessee, unless agreed to by the Director.
(3) In the application of paragraphs (d)(1) and (d)(2) of this section, there shall be no equalization of actual gross trucking costs of $200 or less, excluding accessorial charges.
(e)
(1) Contract services (including professional consulting services and contract services of technical personnel) that are entirely performed in the NPSL project area and benefit exclusively NPSL operations may be charged at the rates specified in the contract.
(2) Contract services (including professional consulting services and contract services of technical personnel) that are entirely performed in the NPSL project area and benefit the NPSL operations and operations on other tracts must be allocated among all tracts benefited and only that portion representing services benefiting the NPSL tract charged to NPSL operations.
(3) Contract services (including professional consulting services and contract services of technical personnel) that are performed at sites outside the NPSL project area may be charged to NPSL operations only if:
(i) The contracted services charged to the NPSL operations benefit only the NPSL tract or support NPSL operations;
(ii) The contract under which such services are provided deals exclusively with services benefiting the NPSL tract or NPSL operations, or the costs of the contract services which are applicable to the NPSL tract or NPSL operations are separately and specifically identified in the contract; and
(iii) Services specified in the contract relate to the resolution of specific technical problems confronting NPSL operations, or specific engineering design problems related to equipment or facilities required for NPSL operations.
(4) The cost of any contract service related to research and development is specifically excluded, as are contract services calling for feasibility studies not directly related to specific engineering design problems or alternatives for equipment and facilities required by NPSL operations.
(f)
(g)
(ii) The term
(2) In lieu of charges in paragraph (g)(1) of this section, the lessee may elect to use average commercial rates prevailing in the vicinity of the NPSL project area less 20 percent. For automotive equipment, the lessee may elect to use rates established by the Director. For other equipment for which no commercial rate exists, the lessee shall submit the basis for determining such costs to the Director for approval.
(h)
(i)
(j)
(2) NPSL operations shall be credited for all reimbursements for costs of damage to NPSL property or personal injury. Reimbursements for damaged NPSL property shall be credited as follows:
(i) If the damaged NPSL property is replaced or repaired, to the NPSL capital account charged for the cost of replacement or repair; or
(ii) If the damaged NPSL property is not replaced or repaired, to the NPSL capital account except that if the cost of the property originally qualified for the allowance for capital recovery in § 220.020, the credit shall be calculated pursuant to § 220.021(a)(3).
(k)
(l)
(m)
(n)
(o)
(p)
(a) During the capital recovery period the overhead allowance shall be calculated on a percentage basis at the rate of 4 percent of allowable direct and allocable joint costs charged to the NPSL capital account, exclusive of costs specified in paragraph (c) of this section. This overhead allowance shall be debited to the NPSL capital account in accordance with § 220.021(b)(2).
(b) For each month after the end of the capital recovery period, an overhead allowance shall be calculated on a percentage basis at the rate of 10 percent of allowable direct and allocable joint costs charged to the NPSL capital account, exclusive of costs specified in paragraph (c) of this section. This overhead allowance shall be debited to the NPSL capital account in accordance with § 220.021(c)(2).
(c) Overhead shall not be charged on the value of:
(1) Lease rental (§ 220.011(a));
(2) Contract services (§ 220.011(e));
(3) Taxes (§ 220.011(i));
(4) Re-injected hydrocarbons, originally produced from the NPSL tract, that are charged under § 220.011(c); and
(5) Credits for materiel charged under § 220.011(c) that are salvaged, returned, or used for the benefit of non-NPSL operations.
The following costs shall not be charged as direct or joint costs to NPSL operations:
(a) Bonus payments to the United States;
(b) Interest (except as permitted under § 220.011(g));
(c) Depreciation, depletion, amortization, or any other charge for capital recovery for materiel charged to the NPSL capital account under § 220.011(c), except as explicitly provided by the allowance for capital recovery calculated according to § 220.020;
(d) The cost of taking inventory;
(e) Research and development costs;
(f) The following legal expenses:
(1) The costs of litigation against the Federal government;
(2) Fines or penalties levied by any Federal agency;
(3) Settlement of claims or other litigation resulting from the lessee's violation of regulatory requirements or negligence; and
(4) The cost of the lessee's legal staff or expense of outside attorneys, except as explicitly allowed under § 220.011(f);
(g) The following employee relocation costs (whether incurred by the employee or the lessee):
(1) Loss on the sale of a home;
(2) Purchase price of a home in the new location;
(3) Payments for employee income taxes incident to reimbursed relocation costs; and
(4) Any relocation cost in connection with an employee move that is for the primary benefit of the lessee's non-NPSL operations;
(h) The lessee's own cost of administering employee benefit plans;
(i) The cost of acquiring or constructing shore base facilities and real property improvements that are charged to NPSL operations on a rental basis under § 220.011(g);
(j) Rentals on any facilities, the investment costs of which have been charged either directly or as allocable joint costs, to the NPSL capital account; and
(k) Pre-NPSL expenditures.
(a) Joint costs shall be grouped in cost pools for allocation to NPSL and non-NPSL operations in reasonable proportion to the beneficial or causal relationships which exist between a specific cost pool and the operations. That portion of a joint cost pool that may be allocated to NPSL operations is called an allocable joint cost.
(b) The following allocation principles apply in allocating joint costs:
(1)
(2)
(3)
(4)
(c) Joint credits shall be allocated in the same manner as joint costs.
(d) When the NPSL is made a part of a unit, the allowed costs shall be charged to the NPSL capital account on the basis specified in the unit operating agreement as approved by the Director. Revenues and other credits shall be made to the NPSL accounts on the same basis as specified in the approved operating agreement. Joint costs of an NPSL and a non-NPSL tract that are adjacent to one another and are on the same structure shall be allocated on a basis approved by the Director.
(a)(1)
(2)
(i)
(B)
(C) Other materiel shall be priced at the current price in effect at date of movement, as listed by a reliable supply store or f.o.b. railway receiving point nearest the NPSL tract where such materiel is normally available.
(ii)
(A) Materiel transferred to the NPSL project area shall be priced at 75 percent of current Condition A price.
(B) Materiel transferred from the NPSL project area shall be priced:
(iii)
(B)
(iv)
(b)
(2) Materiel involving erection costs shall be charged at the applicable percentage of the current knocked-down price of new materiel.
(c) When materiel subject to paragraphs (a)(2) (ii) and (iii) of this section is transferred, the cost of reconditioning shall be borne by the receiving party.
(a) For purposes of this section, the cost base for the allowance for capital recovery in a particular month shall consist of the sum of:
(1) All allowable direct and allocable joint costs chargeable to the NPSL capital account during the month less any costs specified in § 220.012(c); plus
(2) The value of contract services chargeable to the NPSL capital account during the month pursuant to § 220.011(e); plus
(3) The capital recovery period overhead allowance, calculated in accordance with § 220.012(a), that is chargeable to the NPSL capital account for the month; less
(4) Production revenues and other credits received during the month.
(b) If the cost base for a month is greater than zero (that is, if the sum of the charges specified in paragraphs (a) (1) through (3) of this section exceeds the value of production revenues and other credits), the allowance for capital recovery shall be calculated by multiplying the cost base by the capital recovery factor, and shall be debited to the NPSL capital account as specified in § 220.021(b).
(c) If the cost base for a month is less than zero, the allowance for capital recovery for the NPSL capital account shall be calculated by multiplying the resulting negative cost base by the capital recovery factor. The negative product of this calculation shall be debited to the NPSL capital account as specified in § 220.021(b).
(d) No allowance for capital recovery shall be calculated on the charges or credits related to any time period after the end of the capital recovery period.
(a) During each month of the lease term, the NPSL capital account shall be:
(1) Debited with allowable direct and allocable joint costs;
(2) Credited with an amount reflecting the production revenues for the
(3) Credited with amounts properly credited back to the NPSL capital account as specified in § 220.011(p). Credits associated with charges to the NPSL capital account during the capital recovery period, however, shall first be increased by the value of the credit multiplied by the recovery factor, before crediting that sum to the NPSL capital account.
(b) At the end of each month of the lease term during the capital recovery period:
(1) The transactions specified in paragraph (a) of this section shall be made to the NPSL capital account.
(2) The capital recovery period overhead allowance shall be calculated in accordance with § 220.012(a) and debited to the NPSL capital account.
(3) The allowance for capital recovery shall be calculated in accordance with § 220.020 and the allowance debited (or the negative allowance debited, as appropriate) to the NPSL capital account. (A debit entry of a negative allowance for capital recovery shall have the same effect as a credit entry of the absolute value of the allowance for capital recovery.)
(4) The balance in the NPSL capital account shall be calculated. If, as a result of the accounting transactions described in paragraphs (b) (1) through (3) of this section, there is a credit balance in the NPSL capital account, the capital recovery period will be considered terminated as of this month. The credit balance will be forwarded to the next month, which will be the first month for which a profit share payment is due.
(c) At the end of each month of the lease term following the end of the capital recovery period:
(1) The transaction specified in paragraph (a) of this section shall be made to the NPSL capital account.
(2) An overhead allowance shall be calculated in accordance with § 220.012(b) and debited to the NPSL capital account.
(3) The balance in the NPSL capital account shall be calculated.
(d) If, as a result of the accounting transactions described in paragraph (c) of this section, there is a credit balance in the NPSL capital account, this credit balance is the net profit share base for that month. The opening debit and credit balances in the NPSL capital account for any month following a month in which there is a credit balance in the NPSL capital account (except as provided in paragraph (b)(4)) of this section shall be zero.
(e) If, as a result of the accounting transactions described in paragraph (b) or (c) of this section, there is a debit balance in the NPSL capital account, this debit balance shall be the opening debit balance in the NPSL capital account for the following month.
(f) Any credit balance in the NPSL capital account shall become the net profit share base as described in this section. Any debit balance in the NPSL capital account shall be maintained only insofar as necessary for the determination of profit share payments. Such debit balance shall not represent a claim against the United States.
The net profit share payment shall be calculated by multiplying the net profit share base calculated in accordance with § 220.021 by the net profit share rate. The net profit share payment shall be paid to the United States in accordance with § 220.031.
(a) Each lessee subject to this part 220 shall establish and maintain such records as are necessary to determine for each NPSL:
(1) The volume and disposition of all oil and gas production saved, removed or sold for each month;
(2) The value of all oil and gas production saved, removed or sold for each month;
(3) The amount and description of costs and credits to the NPSL capital account;
(4) The amount and description of all costs of acquisition, construction, and operation of equipment and facilities furnished by the lessee and charged to the NPSL capital account under
(5) The cumulative balance of costs and credits to the NPSL capital account; and
(6) The inventory of materiel.
(b) The ledger cards showing the charges and credits to the NPSL capital account shall be maintained until thirty-six months after the cessation of NPSL operations by the lessee. All other documents, journals and records shall be maintained for thirty-six months from the due date or date of mailing of the statement of account on an NPSL, whichever comes later, except that nothing in these regulations shall limit the time of investigation or the need to produce records when prima facie evidence of fraud or willful misconduct is obtained with respect to the government's interest in the NPSL.
(a) Each lessee subject to this part shall file an annual report during the period from issuance of the NPSL until the first month in which production revenues are credited to the NPSL capital account. Such report shall list the costs incurred, including allowances applied, credits received, and the balance of the NPSL capital account. Not later than 60 days after the end of the first month in which production revenues are credited to the NPSL capital account, a final report relating to the period shall be filed.
(b) Beginning with the first month in which production revenues are credited to the NPSL capital account, each lessee subject to this part 220 shall file a report for each NPSL, not later than 60 days following the end of each month, containing the following information for the month for which the report is filed:
(1) The volume and disposition of all oil and gas production saved, removed or sold;
(2) The production revenue;
(3) The amount and description of all costs and credits to the NPSL capital account;
(4) The balance of the NPSL capital account; and
(5) The net profit share base and net profit share payment due the United States and the monthly profit share of the lessee.
(c) Each lessee subject to this part 220 shall submit, together with the report required by paragraph (b) of this section, any net profit share payment due the United States for the period covered by the report.
(d) Each lessee subject to this part 220 shall file a report not later than 90 days after each inventory is taken, reporting the controllable materiel on hand, acquired, transferred or used.
(e) Each lessee subject to this part 220 shall file a final report, not later than 60 days following the cessation of production, together with the appropriate net profit share payment, indicating the remaining balance and costs and credits to the NPSL capital account for the period.
(f) Reports required by this section shall be filed with the Director, either separately or as part of the reports that are currently filed.
(g) Interest shall be calculated at the prevailing rate or rates as published in the Bulletin to the Department of the Treasury Fiscal Requirement Manual, in effect for the period or periods over which the net profit share payment is owed, compounded monthly, on the amount of a net profit share payment, from the due date (60 days following the end of each month for which the payment was due) of a net profit share payment until such payment is received by the United States.
(a) The lessee is responsible for NPSL materiel and shall make proper and timely cost and credit notations for all materiel movements affecting NPSL property. The lessee shall provide only such materiel as may be required for immediate use or is consistent with practical, efficient, and economical operations. The accumulation of surplus stocks shall be avoided by proper materiel control, inventory and purchasing. The lessee shall make timely disposition of idle and surplus materiel through sale.
(b) At reasonable intervals, but at least once every three years, inventories of controllable materiel shall be taken by the lessee. Written notice of intention to take inventory shall be given by the lessee at least 30 days before any inventory is to be taken so that the Director may be represented at the taking of inventory. Failure of the Director to be represented at an inventory shall bind the Director to accept the inventory taken by the lessee, except in the case of willful misrepresentation or fraud.
(c) Inventory shall be valued with any generally accepted accounting method used by the lessee to value the same materiel for financial or income tax reporting purposes, provided that the method is consistently applied throughout the life of the materiel.
(d) Reconciliation shall be made of a physical inventory with the NPSL capital account by the lessee, and a list of overages and shortages shall be available to the Director for audit as provided in § 220.033. Inventory adjustments of controllable materiel shall be made by the lessee to the NPSL capital account for overages and shortages. Controllable materiel removed from physical inventory that has not been credited to NPSL operations under § 220.015(a)(2) shall be credited to NPSL operations at its original value, except that when the cost of the materiel originally qualified for the allowance for capital recovery in § 220.020, the credit shall be calculated pursuant to § 220.021(a)(3).
(a) The accounts of an NPSL lessee or of a contractor of the lessee which are related to NPSL operations shall be subject to audit by DOI or its appointed agent. Where possible, the auditor for DOI shall coordinate audit efforts with other nonoperators, if any. DOI shall have the right to initiate an audit any time within thirty-six months of the due date of the monthly statement that is to be audited or the date that the statement was mailed, whichever is later, provided, however, that audits may not be conducted any more frequently than once every year except upon a showing of fraud or willful misrepresentation.
(b)(1) When nonoperators of an NPSL lease call an audit in accordance with the terms of their operating agreement, the Director shall be notified of the audit call in the same manner as the operator is notified. DOI may elect to send an auditor with the audit team specified by the nonoperators in lieu of calling for a separate audit by DOI.
(2) If DOI determines to call for an audit, DOI shall notify the lessee of its audit call and set a time and place for the audit. Such a notice shall be sent at least thirty days before the suggested time for the audit to allow the nonoperators to join in DOI's audit in lieu of calling for their own audit. The place for the audit will normally be the place where the lessee maintains its records pertaining to the NPSL lease. The lessee shall send copies of the notice to the nonoperators on the lease. The lessee shall use reasonable effort to notify all nonoperators, but failure to include one or more nonoperators in the notification shall not void the notice.
(3) When DOI calls for an audit, DOI may suggest the date and time when the audit may commence. The estimated duration of the audit may be mentioned to the lessee as well as to the other nonoperators who may elect to supply and auditor for their own audit purposes. The lessee's office where the audit will be held may be named or, if not known, inquired about. If a visit to a field plant or field office is contemplated by the government auditor, such a field trip may be mentioned. If DOI expresses a desire to review a period on which the thirty-six month time limitation has expired, it is the lessee's prerogative to allow the review or to request that DOI adhere to the time limitation specified in these regulations.
(c)(1) Exceptions to the accounting by the lessee, whether in favor of the government or the lessee, shall be noted in a report to the lessee. The lessee shall have 60 days from the mailing of a notice of exceptions to agree to the adjustments proposed by the DOI auditor or to object to the proposed adjustments. If the lessee accepts the proposed adjustments, the adjustment shall be booked in the month in which
(2) If the lessee disagrees with the adjustment, the lessee shall have the right to appeal the adjustment to the Director.
(d) Upon receipt of an agreement by the government auditor that there are no required audit adjustments, upon final determination with respect to any audit adjustment proposed by the government auditor, or upon the lapse of thirty-six months from the due date or date of mailing of the statement of account on an NPSL lease, whichever comes later, the books shall be closed for audit adjustment purposes, except upon a showing of fraud or willful misrepresentation.
(e) Records required to be kept under § 220.030(a) shall be made available for inspection by any authorized agent of DOI at any time during normal business hours upon the request of the Director or other authorized official.
(a) If, as a result of an inspection of records or an audit under § 220.033, the Director determines that there is an error in the NPSL capital account or an error in calculating the net profit share payment, whether in favor of the government or the lessee, the Director shall redetermine the net profit share base and recalculate the net profit share payment due the United States and notify the lessee of the recalculation.
(b) The lessee shall pay any additional amount of net profit share payment owed plus interest, compounded monthly, from the date that the payment was due until the date it is actually paid. Interest shall be calculated at the prevailing rate or rates as published in the Bulletin to the Department of the Treasury Fiscal Requirements Manual, in effect for the period or periods over which the payment is owed.
(c) If the recalculated profit share payment is less than the amount paid the United States, the lessee shall apply such overpayment to the next profit share payment.
(d) Within 30 days after receiving notice of the recalculation as provided in paragraph (a) of this section, the lessee may appeal the decision of the Director in accordance with the appeals provision of 30 CFR part 290.
30 U.S.C. 1735; 30 U.S.C. 196; Pub L. 102-154.
This part provides procedures to delegate Federal royalty management functions to States under section 205 of the Federal Oil and Gas Royalty Management Act of 1982 (the Act), 30 U.S.C. 1735, as amended by the Federal Oil and Gas Royalty Simplification and Fairness Act of 1996, Pub. L. 104-185, August 13, 1996, as corrected by Pub. L. 104-200. This part also provides procedures to delegate only audit and investigation functions to States under Pub. L. 102-154 for solid mineral leases, geothermal leases and leases subject to section 8(g) of the Outer Continental Shelf Lands Act, 43 U.S.C. 1337(g). This part does not apply to any inspection or enforcement responsibilities of the Bureau of Land Management for onshore leases or the MMS Offshore Minerals Management program for leases on the Outer Continental Shelf.
(a) The information collection requirements contained in this part have been approved by Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. and assigned OMB Control Number 1010-0088. We will use the information collected to review and approve delegation proposals from States wishing to perform royalty management functions.
(b) Public reporting burden is estimated as follows. MMS estimates 400 annual burden hours per function for each State performing the delegated functions. The Federal Government will reimburse some of these costs as provided by statute. However, States could incur additional start-up costs, such as purchasing equipment necessary to perform a delegated function, that may not be reimbursable. MMS estimates that, if applicable, each payor or reporter would spend 50 burden hours annually coordinating their interactions and communications among the several States and with MMS. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing burden, to the Information Collection Clearance Officer, Minerals Management Service, 1849 C Street, NW., Washington, DC 20240; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Attention: Desk Officer for the Interior Department, OMB Control Number 1010-0088, 725 17th Street, NW., Washington, DC 20503.
(a) If there are oil and gas leases subject to the Act on Federal lands within your State, MMS may delegate the following royalty management functions for all such Federal oil and gas leases to you under this part:
(1) Receiving and processing production or royalty reports;
(2) Correcting erroneous report data; and
(3) Performing automated verification.
(b) If there are oil and gas leases subject to the Act on Federal lands within your State, MMS may delegate the following royalty management functions for some or all of the Federal oil and gas leases to you under this part:
(1) Conducting audits and investigations; and
(2) Issuing demands, subpoenas, and orders to perform restructured accounting, including related notices to lessees or their designees, and entering into tolling agreements under section 115(d)(1) of the Act, 30 U.S.C. 1725(d)(1).
(c) If there are oil and gas leases offshore of your State subject to section 8(g) of the Outer Continental Shelf Lands Act, 43 U.S.C. 1337 (g), or solid mineral leases or geothermal leases on Federal lands within your State, MMS may delegate authority to conduct audits and investigations for some or all such Federal leases.
This section lists the principal royalty management functions that MMS will not delegate to a State. MMS will not delegate to a State the following functions:
(a) MMS must collect all moneys received from sales, bonuses, rentals, royalties, civil penalties, assessments and interest. MMS also must collect any moneys a lessee or its designee pays because of audits or other actions of a delegated State;
(b) MMS must compare all cash and other payments it receives with payments shown on royalty reports or other documents, such as bills, to reconcile payor accounts. MMS also must disburse all appropriate moneys to States and other revenue recipients, including refunds and interest owed to lessees and their designees;
(c) The Department of the Interior will receive, process, and decide all administrative appeals from demands or other orders issued to lessees, their designees, or any other person, including demands or orders a delegated State issues;
(d) Only MMS may take enforcement actions other than issuing demands, subpoenas and orders to perform restructured accounting. MMS or the appropriate Federal agency will issue notices of non-compliance and civil penalties, collect debts, write off delinquent debts, pursue litigation, enforce subpoenas, and manage any alternative dispute resolution. MMS will conduct, coordinate and approve any settlement or other compromise of an obligation that a lessee or its designee owes;
(e) MMS will decide all valuation policies, including issuing valuation regulations, determinations, and guidelines, and interpreting valuation regulations; and
(f) MMS may reserve additional authorities and responsibilities not included in paragraphs (a) through (f) of this section.
If you want MMS to delegate royalty management functions to you, then you must submit a delegation proposal to the MMS Associate Director for Royalty Management. MMS will provide you with technical assistance and information to help you prepare your delegation proposal. Your proposal must contain the following minimum information:
(a) The name and title of the State official authorized to submit the delegation proposal and execute the delegation agreement;
(b) The name, address, and telephone number of the State contact for the proposal;
(c) A copy of the legislation, State Attorney General opinion or other document that:
(1) States which State entity or entities are responsible for performing delegated functions, and if more than one entity is delegated such responsibility, the position of the highest ranking State official having ultimate authority over the collection of royalties from leases on Federal lands within the State;
(2) Demonstrates the State's authority to:
(i) Accept a delegation from MMS; and
(ii) Receive State or Federal appropriations to perform delegated functions;
(d) The date you propose to begin performing delegated functions;
(e) A detailed statement of the delegable functions that you propose to perform. For each function, describe the resources available in your State to perform each function, the procedures you will use to perform each function, and how you will assure that you will meet all Federal laws, lease terms, regulations and relevant performance standards. As evidence that you have or will have the resources to perform each delegable function, provide the following information:
(1) A description of the personnel you have available to perform delegated functions, including:
(i) How many persons you will assign full-time and part-time to each delegated function;
(ii) The technical qualifications of the key personnel you will assign to each function, including academic field and degree, professional credentials, and quality and amount of experience with similar functions; and
(iii) Whether these persons are currently State employees. If not, explain how you propose to hire these persons or obtain their services, and when you expect to have those persons available to perform delegated functions;
(2) A description of the facilities you will use to perform delegated functions, including:
(i) Whether you currently have the facilities in which you will physically locate the personnel and equipment you will need to perform the functions you propose to assume. If not, how you propose to acquire such facilities, and when you expect to have such facilities available; and
(ii) How much office space is available;
(3) Describe the equipment you will use to perform delegated functions, including:
(i) Hardware and software you will use to perform each delegated function, including equipment for:
(A) Document processing, including compatibility with MMS automated systems, electronic commerce capabilities, and data storage capabilities;
(B) Accessing reference data;
(C) Contacting production or royalty reporters;
(D) Issuing demands;
(E) Maintaining accounting records;
(F) Performing automated verification;
(G) Maintaining security of confidential and proprietary information; and
(H) Providing data to other Federal agencies;
(ii) Whether you currently have the equipment you will need to perform the functions you propose to assume. If not, how you propose to acquire such equipment and when you expect to have such equipment available;
(f) Your estimates of the costs to fund the following resources necessary to perform the delegation:
(1) Personnel, including hiring, employee salaries and benefits, travel and training;
(2) Facilities, including acquisition, upgrades, operation, and maintenance; and
(3) Equipment, including acquisition, operation, and maintenance;
(g) Your plans to fund the resources under paragraph (f) of this section, including any items you will ask MMS to fund under the delegation agreement;
(h) A statement identifying any areas where State law, including State appropriation law, may limit your ability to perform delegated functions, and an explanation of how you propose to remove any such limitation;
(i) A statement that in accordance with section 203 of the Act (30 U.S.C. 1733) persons who have access to information received under delegated functions are subject to the same provisions of law regarding confidentiality and disclosure of that information as Federal employees. Applicable laws include the Freedom of Information Act (FOIA), the Trade Secrets Act, and relevant Executive Orders. In addition, your statement must acknowledge that all documents produced, received, and maintained as part of any delegation functions are agency records for purposes of FOIA. Therefore, persons who have access to information received under delegated functions may not use such information or provide such information to any other person, including State personnel, for purposes other
When MMS receives your delegation proposal, it will record the receipt date. MMS will notify you in writing within 15 business days whether your proposal is complete. If it is not complete, MMS will identify any missing items § 227.103 requires. Once you submit all required information, MMS will notify you of the date your application is complete.
After MMS notifies you that your delegation proposal is complete, MMS will schedule a hearing on your proposal, if MMS determines a hearing is appropriate, as follows:
(a) The MMS Director will appoint a hearing official to conduct one or more public hearings for fact finding regarding your ability to assume the delegated functions requested. The hearing official will not decide whether to approve your delegation request;
(b) The hearing official will contact you about scheduling a hearing date and location;
(c) The MMS will publish notice of the hearing in the
(d) MMS will publish notice of the proposal in the
(e) At the hearing, you will have an opportunity to present testimony and written information in support of your proposal;
(f) Other persons may attend the hearing and may present testimony and written information for the record;
(g) MMS will record the hearing;
(h) MMS will maintain a record of all documents related to the proposal process;
(i) After the hearing, MMS may require you to submit additional information in support of your delegation proposal.
The MMS Director will decide whether to approve your delegation request and will ask the Secretary of the Interior to concur in the decision. That decision is solely within the MMS Director's and the Secretary's discretion. The MMS Director's decision, which the Secretary concurs in, is the final decision for the Department of the Interior. The MMS Director may approve a State's request for delegation only if, based upon the State's delegation proposal and the hearing record, the MMS Director finds that:
(a) It is likely that the State will provide adequate resources to achieve the purposes of the Act;
(b) The State has demonstrated that it will effectively and faithfully administer the MMS regulations under the Act in accordance with subsections (c) and (d) of section 205 of the Act;
(c) Such delegation will not create an unreasonable burden on any lessee;
(d) The State agrees to adopt standardized reporting procedures MMS prescribes for royalty and production accounting purposes, unless the State and all affected parties (including MMS) otherwise agree;
(e) The State agrees to follow and adhere to regulations and guidelines MMS issues under the mineral leasing laws regarding valuation of production; and
(f) Where necessary for a State to carry out and enforce a delegated activity, the State agrees to enact such laws and promulgate such regulations as are consistent with relevant Federal laws and regulations.
The MMS Director will decide whether to approve your delegation proposal
MMS will notify you in writing of its decision on your delegation proposal. If MMS approves your delegation proposal, then MMS will hold discussions with you to develop a delegation agreement detailing the functions that you will perform, the standards and requirements you must comply with to perform those functions, and any required transition period.
If the MMS Director denies your delegation proposal, MMS will state the reasons for denial. MMS also will inform you in writing of the conditions you must meet to receive approval. You may submit a new delegation proposal at any time following a denial.
(a) Delegation agreements are effective for 3 years from the date the MMS Director signs the delegation agreement. However, during the development of the State's delegation proposal under § 227.108 of this part, MMS, the delegated State, and any other affected person will determine an appropriate transition period for lessees and their designees to modify their systems to comply with any new requirements under a delegation agreement. MMS will publish notice of the effective date of a State's delegation agreement in the
(b) You may ask MMS to renew the delegation for an additional 3 years no less than 6 months before your 3-year delegation agreement expires. You must submit your renewal request to the MMS Associate Director for Royalty Management as follows:
(1) If you do not want to change the terms of your delegation agreement for the renewal period, you need only ask to extend your existing agreement for the 3-year renewal period. MMS will not schedule a hearing unless you request one;
(2) If you want to change the terms of your delegation agreement for the renewal period, you must submit a new delegation proposal under this part.
(c) The MMS Director may approve your renewal request only if MMS determines that you are meeting the requirements of the applicable standards and regulations. If the MMS Director denies your renewal request, MMS will state the reasons for denial. MMS also will inform you in writing of the conditions you must meet to receive approval. You may submit a new renewal request any time after denial.
(d) After the 3-year renewal period for your delegation agreement ends, if you wish to continue performing one or more delegated functions, you must request a new delegation agreement from MMS under this part. MMS will schedule a hearing on your request, if MMS determines a hearing is appropriate. As part of the decision whether to approve your request for a new delegation, the MMS Director will consider whether you are meeting the requirements of the applicable standards and regulations under your existing delegation agreement.
(e) If you do not request a hearing under paragraphs (b)(1) or (d) of this section, any other affected person may submit a written request for a hearing under those paragraphs to the MMS Associate Director for Royalty Management.
This section explains your options if you have a delegation agreement in effect on the effective date of this regulation.
(a) If you do not want to perform any royalty management functions in addition to those authorized under your existing agreement, you may continue
(b) If you want to perform royalty management functions in addition to those authorized under your existing agreement, you must request a new delegation agreement under this part.
(c) MMS may extend any delegation agreement in effect on the effective date of this regulation for up to 3 years beyond the date it is due to expire.
You will receive compensation for your costs to perform each delegated function subject to the following conditions:
(a) Compensation for costs is subject to Congressional appropriations;
(b) Compensation may not exceed the reasonably anticipated expenditures that MMS would incur to perform the same function;
(c) The cost for which you request compensation must be directly related to your performance of a delegated function and necessary for your performance of that delegated function;
(d) At a minimum, you must provide vouchers detailing your expenditures quarterly during the fiscal year. However, you may agree to provide vouchers on a monthly basis in your delegation agreement;
(e) You must maintain adequate books and records to support your vouchers;
(f) MMS will pay you quarterly or monthly during the fiscal year as stated in your delegation agreement; and
(g) MMS may withhold compensation to you for your failure to properly perform any delegated function as provided in section 227.801 of this part.
For each delegated function you perform, you must:
(a) Operate in compliance with all Federal laws, regulations, and Secretarial and MMS determinations and orders relating to calculating, reporting, and paying mineral royalties and other revenues. You must seek information or guidance from MMS regarding new, complex, or unique issues. If MMS determines that written guidance or interpretation is appropriate, MMS will provide the guidance or interpretation in writing to you and you must follow the interpretation or guidance given;
(b) Comply with Generally Accepted Accounting Principles (GAAP). You must:
(1) Provide complete disclosure of financial results of activities;
(2) Maintain correct and accurate records of all mineral-related transactions and accounts;
(3) Maintain effective controls and accountability;
(4) Maintain a system of accounts that includes a comprehensive audit trail so that all entries may be traced to one or more source documents; and
(5) Maintain adequate royalty and production information for royalty management purposes;
(c) Assist MMS in meeting the requirements of the Government Performance and Results Act (GPRA) as well as assisting in developing and endeavoring to comply with the MMS Strategic Plan and Performance Measurements;
(d) Maintain all records you obtain or create under your delegated function, such as royalty reports, production reports, and other related information. You must maintain such records in a safe, secure manner, including taking appropriate measures for protecting confidential and proprietary information and assisting MMS in responding to Freedom of Information Act requests when necessary. You must maintain such records for at least 7 years;
(e) Provide reports to MMS about your activities under your delegated functions. MMS will specify in your delegation agreement what reports you must submit and how often you must submit them. At a minimum, you must provide periodic statistical reports to MMS summarizing the activities you carried out, such as:
(1) Production and royalty reports processed;
(2) Erroneous reports corrected;
(3) Results of automated verification findings;
(4) Number of audits performed; and
(5) Enforcement documents issued.
(f) Assist MMS in maintaining adequate reference, royalty, and production databases as provided in the
(g) Develop annual work plans that:
(1) Specify the work you will perform for each delegated function; and
(2) Identify the resources you will commit to perform each delegated function;
(h) Help MMS respond to requests for information from other Federal agencies, Congress, and the public;
(i) Cooperate with MMS's monitoring of your delegated functions; and
(j) Comply with the
(a) If MMS delegates royalty management functions to you, you must comply with the
(b) Your delegation agreement may include additional standards specifically applicable to the functions delegated to you.
(c) Failure to comply with your delegation agreement, the
(d) MMS may revise the
An audit consists of an examination of records to verify that royalty reports and payments accurately reflect actual production, sales, revenues and costs, and compliance with Federal statutes, regulations, lease terms, and MMS policy determinations.
(a) If you request delegation of audit functions, you must perform at least the following:
(1) Submitting requests for records;
(2) Examining royalty and production reports;
(3) Examining lessee production and sales records, including contracts, payments, invoices, and transportation and processing costs to substantiate production and royalty reporting;
(4) Providing assistance to MMS for appealed demands or orders, including preparing field reports, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.
(b) If necessary for a particular audit, you may also perform any of the following:
(1) Issuing engagement letters;
(2) Arranging for entrance conferences;
(3) Scheduling site visits; and
(4) Issuing record releases and audit closure letters; and
(5) Holding closeout conferences.
If you perform audits you must:
(a) Comply with the
(b) Follow the MMS Annual Audit Work Plan and 5-year Audit Strategy, which MMS will develop in consultation with States having delegated audit authority;
(c) Agree to undertake special audit initiatives MMS identifies targeting specific royalty issues, such as valuation or volume determinations;
(d) Prepare, construct, or compile audit work papers under the appropriate procedures, manuals, and guidelines;
(e) Prepare and submit MMS Audit Work Plans. You may modify your Audit Work Plans with MMS approval; and
(f) Comply with procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.
Production reporters or royalty reporters provide production, sales, and royalty information on mineral production from leases that must be collected, analyzed, and corrected.
(a) If you request delegation of either production report or royalty report processing functions, you must perform at least the following:
(1) Receiving, identifying, and date stamping production reports or royalty reports;
(2) Processing production or royalty data to allow entry into a data base;
(3) Creating copies of reports by means such as electronic imaging;
(4) Timely transmitting production report or royalty report data to MMS and other affected Federal agencies as provided in your delegation agreement and the
(5) Providing training and assistance to production reporters or royalty reporters;
(6) Providing production data or royalty data to MMS and other affected Federal agencies; and
(7) Providing assistance to MMS for appealed demands or orders, including meeting timeframes, supplying information, using the appropriate format, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.
(b) If you request delegation of either production report or royalty report processing functions, or both, you may perform the following functions:
(1) Granting exceptions from reporting and payment requirements for marginal properties; and
(2) Approving alternative royalty and payment requirements for unit agreements and communitization agreements.
(c) You must provide MMS with a copy of any exceptions from reporting and payment requirements for marginal properties and any alternative royalty and payment requirements for unit agreements and communitization agreements you approve.
In processing production reports or royalty reports you must:
(a) Process reports accurately and timely as provided in the
(b) Identify and resolve fatal errors to use in subsequent error correction that the State or MMS performs;
(c) Accept multiple forms of electronic media from reporters, as MMS specifies;
(d) Timely transmit required production or royalty data to MMS and other affected Federal agencies;
(e) Access well, lease, agreement, and reporter reference data from MMS and provide updated information to MMS;
(f) For production reports, maintain adequate system software edits to ensure compliance with the provisions of 30 CFR part 216, the
(g) For royalty reports, maintain adequate system software edits to ensure compliance with the provisions of 30 CFR part 218, the
(h) Comply with the procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.
Production data and royalty data must be edited to ensure that what is reported is correct, that disbursement
(a) Correcting all fatal errors and assigning appropriate confirmation indicators;
(b) Verifying whether production reports are missing;
(c) Contacting production reporters or royalty reporters about missing reports and resolving exceptions;
(d) Documenting all corrections made, including providing production reporters or royalty reporters with confirmation reports of any changes;
(e) Providing training and assistance to production reporters or royalty reporters;
(f) Issuing notices, orders to report, and bills as needed, including, but not limited to, imposing assessments on a person who chronically submits erroneous reports; and
(g) Providing assistance to MMS for appealed demands or orders, including preparing field reports, performing remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.
To ensure the correction of erroneous data, you must:
(a) Ensure compliance with the provisions of 30 CFR parts 216 and 218, any applicable handbook specified under 30 CFR 227.401 (f) and (g), interagency memorandums of understanding to which MMS is a party, and the
(b) Ensure that reporters accurately and timely correct all fatal errors as designated in the
(c) Submit accepted and corrected lines to MMS to allow processing into the Auditing and Financial System (AFS) and the Production Accounting and Auditing System (PAAS) in a timely manner as provided in the
(d) Comply with the procedures for appealed demands or orders, including meeting timeframes, supplying information, and using the appropriate format.
Automated verification involves systematic monitoring of production and royalty reports to identify and resolve reporting or payment discrepancies. States may perform the following:
(a) Automated comparison of sales volumes reported by royalty reporters to sales and transfer volumes reported by production reporters. If you request delegation of automated comparison of sales and production volumes, you must perform at least the following functions:
(1) Performing an initial sales volume comparison between royalty and production reports;
(2) Performing subsequent comparisons when reporters adjust royalty or production reports;
(3) Checking unit prices for reasonable product valuation based on reference price ranges MMS provides;
(4) Resolving volume variances using written correspondence, telephone inquiries, or other media;
(5) Maintaining appropriate file documentation to support case resolution; and
(6) Issuing orders to correct reports or payments;
(b) Any one or more of the following additional automated verification functions:
(1) Verifying compliance with lease financial terms, such as payment of rent, minimum royalty, and advance royalty;
(2) Identifying and resolving improper adjustments;
(3) Identifying late payments and insufficient estimates, including calculating interest owed to MMS and verifying payor-calculated interest owed to MMS;
(4) Calculating interest due to a lessee or its designee for an adjustment or refund, including identifying overpayments and excessive estimates;
(5) Verifying royalty rates; and
(6) Verifying compliance with transportation and processing allowance limitations;
(c) Issuing notices and bills associated with any of the functions under paragraphs (a) and (b) of this section; and
(d) Providing assistance to MMS for any of these delegated functions on appealed demands or orders, including meeting timeframes, supplying information, using the appropriate format, taking remanded actions, modifying orders, and providing oral and written briefing and testimony as expert witnesses.
To perform automated verification of production reports or royalty reports, you must:
(a) Verify through research and analysis all identified exceptions and prepare the appropriate billings, assessment letters, warning letters, notification letters, Lease Problem Reports, other internal forms required, and correspondence required to perform any required follow-up action for each function, as specified in the
(b) Resolve and respond to all production reporter or royalty reporter inquiries;
(c) Maintain all documentation and logging procedures as specified in the
(d) Access well, lease, agreement, and production reporter or royalty reporter reference data from MMS and provide updated information to MMS; and
(e) Comply with procedures for appealed demands and orders, including meeting time frames, supplying information, and using the appropriate format.
This section explains what enforcement actions you may take as part of your delegated functions.
(a) You may issue demands, subpoenas, and orders to perform restructured accounting, including related notices to lessees and their designees. You also may enter into tolling agreements under section 15(d)(1) of the Act, 30 U.S.C. 1725(d)(1).
(b) When you issue any enforcement document you must comply with the requirements of section 115 of the Act, 30 U.S.C. 1725.
(c) When you issue a demand or enter into a tolling agreement under section 15(d)(1) of the Act, 30 U.S.C. 1725(d)(1), the highest State official having ultimate authority over the collection of royalties or the State official to whom that authority has been delegated must sign the demand or tolling agreement.
(d) When you issue a subpoena or order to perform a restructured accounting you must:
(1) Coordinate with MMS to ensure identification of issues that may concern more than one State before you issue subpoenas and orders to perform restructured accounting; and
(2) Ensure that the highest State official having ultimate authority over the collection of royalties signs any subpoenas and orders to perform restructured accounting, as required under section 115 of the Act, 30 U.S.C. 1725. This official may not delegate signature authority to any other person.
This section explains MMS's procedures for monitoring your performance of any of your delegated functions.
(a) A monitoring team of MMS officials will annually review your performance of the delegated functions and compliance with your delegation agreement, the
(b) The monitoring team also will:
(1) Periodically review your statistical reports required under § 227.200(e) to verify your accuracy, timeliness, and efficiency;
(2) Check for timely transmittal of production report or royalty report information to MMS and other affected agencies, as applicable, to allow for proper disbursement of funds and processing of information;
(3) Coordinate on-site visits and Office of the Inspector General, General Accounting Office, and MMS audits of your performance of your delegated functions; and
(4) Maintain reports of its monitoring activities.
If your performance of the delegated function does not comply with your delegation agreement, or the
(a) Notify you in writing of your noncompliance or inability to comply. The notice will prescribe corrective actions you must take, and how long you have to comply. You may ask MMS for an extension of time to comply with the notice. In your extension request you must explain why you need more time; and
(b) If you do not take the prescribed corrective actions within the time that MMS allows in a notice issued under paragraph (a) of this section, then MMS may:
(1) Initiate proceedings under § 227.802 to terminate all or a part of your delegation agreement;
(2) Withhold compensation provided to you under § 227.112; and
(3) Perform the delegated function, before terminating or without terminating your delegation agreement, including, but not limited to, issuing a demand or order to a Federal lessee, or its designee, or any other person when:
(i) Your failure to issue the demand or order would result in an underpayment of an obligation due MMS; and
(ii) The underpayment would go uncollected without MMS intervention.
This section explains the procedures MMS will use to terminate all or a part of your delegation agreement:
(a) MMS will notify you in writing that it is initiating procedures to terminate your delegation agreement;
(b) MMS will provide you notice and opportunity for a hearing under § 227.803 of this part;
(c) The MMS Director, with concurrence from the Secretary, will decide whether to terminate your delegation agreement.
(d) After the hearing, MMS may:
(1) Terminate your delegation agreement; or
(2) Allow you 30 days to correct any remaining deficiencies. If you do not correct the deficiency within 30 days, MMS will terminate all or a part of your delegation agreement.
(e) MMS will determine the date your agreement is terminated and will notify you of that date in writing. MMS will determine the termination date based on the number of delegated functions and the impact of the termination on all affected parties.
(a) The MMS Director will appoint a hearing official to conduct one or more public hearings for fact finding and to determine any actions you must take to correct the noncompliance. The hearing official will not decide whether to terminate your delegation agreement;
(b) The hearing official will contact you about scheduling a hearing date and location;
(c) The hearing official will publish notice of the hearing in the
(d) At the hearing, you will have an opportunity to present testimony and written information on your ability to perform your delegated functions as required under this part, your delegation agreement, and the
(e) Other persons may attend the hearing and may present testimony and written information for the record;
(f) MMS will record the hearing;
(g) After the hearing, MMS may require you to submit additional information; and
(h) Information presented at each public hearing will help MMS to determine whether:
(1) You have complied with the terms and conditions of your delegation agreement; or
(2) You have the capability to comply with the requirements under § 227.106 of this part.
You may request MMS to terminate your delegation at any time by submitting your written notice of intent 6 months prior to the date on which you want to terminate. MMS will determine the date your agreement is terminated and will notify you of that date in writing. MMS will determine the termination date based on the number of delegated functions and the impact of the termination on all affected parties.
After your delegation agreement is terminated, you may apply again for delegation by beginning with the proposal process under this part.
Sec. 202, Pub. L. 97-451, 96 Stat. 2457 (30 U.S.C. 1732).
It is the purpose of cooperative agreements to effectively utilize the capabilities of the States and Indian tribes in developing and maintaining an efficient and effective Federal royalty management system as indicated at 30 U.S.C. 1701.
It shall be the policy of DOI to enter into cooperative agreements with States and Indian tribes to carry out audits and related investigations and enforcement actions whenever a State or tribe initiates a request to enter into an agreement and a finding is made that a State or tribe has the ability to carry out cooperative activities in a timely and efficient manner.
As of the effective date of this rule, September 11, 1997, this part does not apply to Federal lands.
The Secretary of the Interior is authorized to enter into cooperative agreements with States and Indian tribes (30 U.S.C. 1732) to share oil or gas royalty management information, and to carry out auditing and related investigation or enforcement activities in cooperation with the Secretary.
(a) Authority to enter into cooperative agreements to carry out audit and related investigation and enforcement activities with State and tribal governments has been delegated to the Director of the Minerals Management Service (MMS).
(b) Authority to enter into cooperative agreements with State and tribal governments to carry out inspection and related investigation and enforcement activities has been delegated to the Director of the Bureau of Land Management (BLM) and is not covered by this part.
(c) The entry into a cooperative agreement with either MMS or BLM will not affect the ability of a State or Indian tribe to choose to enter into such an agreement with the other agency. A State may enter into a delegation agreement (30 U.S.C. 1735) with MMS to perform certain functions without affecting its ability to enter into a cooperative agreement with either MMS or BLM, or both, to cooperate in the performance of those functions which are not delegated in this part.
For the purposes of this part, terms shall have the same meaning as in 30 U.S.C. 1702. In addition, the following definition shall apply:
(a) The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 et seq. and assigned OMB Clearance Number 1010-0087. The information collected will be used to prepare a cooperative agreement with a State or Indian tribe wishing to perform royalty audits. The information should be submitted voluntarily in order to enter into a cooperative agreement authorized by 30 U.S.C. 1732.
(b) Public reporting burden is estimated to average 136 hours for the preparation of the original request for consideration and application to enter into a cooperative agreement. Subsequent requests for renewal of the agreement may require about 40 hours for the preparation of an annual budget and work plan, and an estimated 8 hours per quarter for preparation of a reimbursement voucher and an audit progress report. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing burden, to the Information Collection Clearance Officer, Minerals Management Service, 381 Elden Street, Herndon, Virginia 22070; and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Paperwork Reduction Project 1010-0087, Washington, DC 20503.
(a) A State or Indian tribe may request the Department to enter into a cooperative agreement by sending a letter from the governor, tribal chairman, or other appropriate official with delegation authority, to the Director of MMS.
(b) The request for an agreement shall be in a format prescribed by MMS and should include at a minimum the following information:
(1) Type of eligible activities to be undertaken.
(2) Proposed term of the agreement.
(3) Evidence that the State or Indian tribe meets, or can meet by the time the agreement is in effect, the standards established by the Secretary for the types of activities to be conducted under the terms of the agreement.
(4) If the State is proposing to undertake activities on Indian lands located within the State, a resolution from the appropriate tribal council indicating
(c) The eligible activities to be conducted under the terms of a cooperative agreement may be funded or unfunded by the Department. See § 228.105 of this subpart for funding of cooperative agreements.
(a) Agreements entered into under this part shall be valid for a period of 3 years and shall be renewable or additional consecutive 3-year periods upon request of the State or Indian tribe which is a party to the agreement.
(b) An agreement may be terminated at any time by mutual agreement and upon any terms and conditions as agreed upon by the parties.
(c) A State or Indian tribe may unilaterally terminate an agreement by giving a 120-day written notice of intent to terminate.
(d) The MMS may commence termination of an agreement by giving a 120-day written notice of intent to terminate. MMS shall provide the State or Indian tribe with the reasons for the proposed termination in writing if the termination is proposed because of alleged deficiencies by the State or Indian tribe in carrying out the provisions of the agreement. The State or Indian tribe will be given 60 days to respond to the notice of deficiencies and to provide a plan for correction of those deficiencies. No final action on termination shall be taken until any submission of the State or Indian tribe provided within the above prescribed 60 days has been reviewed by MMS for content or merit.
(e) Termination of a cooperative agreement shall not bar a later request by a State or Indian tribe to enter into a subsequent cooperative agreement.
The MMS, after consultation with States and Indian tribes, shall establish standards for carrying out the activities under the provisions of this part. The standards will be incorporated into the agreement and shall be no more stringent than those applicable to similar activities of the MMS. The States and Indian tribes shall coordinate their planned auditing activities with MMS. Where an MMS audit team is permanently assigned to a lessee/payor, contact by State and Indian tribal auditors with the lessee/payor shall be through the MMS auditor in residence.
(a) The State or Indian tribe entering into a cooperative agreement under this part must retain all records, reports, working papers, and any backup materials for a period specified by MMS. All records and support materials must be available for inspection and review by appropriate personnel of the Department including the Office of the Inspector General.
(b) The State or Indian tribe shall maintain all books and records as may be necessary to assure compliance with the provisions of chapter 1, 48 CFR 31.107 and 48 CFR subpart 31.6 (Contracts with State, local, and federally recognized Indian tribal Governments).
(a) Under the provisions of this part, information necessary to carry out the activities authorized under the terms of a cooperative agreement will be provided by DOI to the States and Indian tribes entering into such agreements. The information will consist of data provided from all relevant sources on a lease level basis for leases located within the boundaries of the State or Indian tribe which has entered into the agreement. This information will include any records or data held by the lessee or other person that have not been submitted to MMS, but that affect Federal lease interests and could be required to be submitted under the lease terms or Federal regulations.
(b) None of the provisions of this subpart should be construed as limiting information already being provided to Indian tribes and allottees regarding their lease interests.
(c) Information will be provided by MMS on a monthly basis and will include data on royalties, rents, and bonuses collected on the lease, volumes produced, sales made, value of products disposed of as a sale and used as a basis for royalty calculation, and other information necessary to allow the State or tribe to carry out its responsibilities under the cooperative agreement.
(d) Proprietary data that is made available to a State or tribe under provisions of 30 U.S.C. 1733 shall be subject to the constraints of 18 U.S.C. 1905. To receive proprietary data, the State or tribe must—
(1) Demonstrate what audit, investigation, or litigation under provisions of 30 U.S.C. 1734 is planned for or underway for which this data is essential;
(2) Demonstrate why this particular data is necessary; and
(3) Agree to safeguard proprietary data as provided.
(a)(1) The Department may, under the terms of the cooperative agreement, reimburse the State or Indian tribe up to 100 percent of the costs of eligible activities. Eligible activities will be agreed upon annually upon the submission and approval of a workplan and funding requirement.
(2) A cooperative agreement may be entered into with a State or Indian tribe, upon request, without a requirement for reimbursement of costs by the Department.
(b) All cooperative agreements under this part are subject to annual funding and the availability of appropriations specifically designated for the purpose of this part.
(c) The State or Indian tribe shall submit a voucher for reimbursement of eligible costs incurred within 30 days of the end of each calendar quarter. The State or Indian tribe must provide the Department a summary of costs incurred, for which the State or Indian tribe is seeking reimbursement, with the voucher.
(a) If a cooperative agreement provides for Federal funding, only costs directly associated with eligible activities undertaken by the State or Indian tribe under the terms of a cooperative agreement will be eligible for reimbursement. Costs of services or activities which cannot be directly related to the support of activities specified in the agreement will not be eligible for Federal funding or for inclusion in the State's share or in the Indian tribe's share of funding that may be established in the agreement.
(b) Eligible costs are the cost of salaries and benefits associated with technical, support, and clerical personnel engaged in eligible activities; direct cost of travel, rentals, and other normal administrative activities in direct support of the project or projects; basic and specialized training for State and tribal participants; and cost of any contractual services which can be shown to be in direct support of the activities covered by the agreement. Each cooperative agreement shall contain detailed schedules identifying those activities and costs which qualify for funding and the procedures, timing, and mechanics for implementing Federal funding.
As provided at 30 U.S.C. 1736, 50 percent of any civil penalty collected as a result of activities under a cooperative agreement will be shared with the State or Indian tribe performing the cooperative agreement; however, the amount of the civil penalty shared will be deducted from any Federal funding owed under that cooperative agreement. MMS shall maintain records of civil penalties collected and distributed to the States and tribes involved in cooperative agreements. Each quarterly payment of the Federal share of a cooperative agreement will be reduced by the amount of the civil penalties paid to the State or tribe during the prior quarter.
30 U.S.C. 1735.
The purpose of this part is to promote the effective utilization of the capabilities of the States in developing and maintaining an efficient and effective Federal royalty management system.
It shall be the policy of the Department of the Interior (DOI) to honor any properly made petition from the Chief Executive or other appopriate official of a State seeking delegation of authority under the provisions of 30 U.S.C. 1735 and to make a delegation to conduct audits and related investigations when the Secretary finds that the provisions of 30 U.S.C. 1735 have been complied with or can be complied with by a State seeking the delegation.
As of the effective date of this rule, September 11, 1997, this part does not apply to Federal lands.
The Secretary of the DOI is authorized under provisons of 30 U.S.C. 1735 to delegate authority to States to conduct audits and related investigations with respect to all Federal lands within a State, and to those Indian lands to which a State has received permission from the respective Indian tribe(s) or allottee(s) to carry out audit activities under a delegation from the Secretary.
The definitions contained in 30 U.S.C. 1702 and in part 228 of this chapter apply to the activities carried out under the provisions of this part.
The information collection requirements contained in this part do not require approval by the Office of Management and Budget under 44 U.S.C. 3501
The Federal Oil and Gas Royalty Management Act of 1982 (30 U.S.C. 1701
(a) All or part of the following authorities and responsibilities of the Secretary under the Act may be delegated to a State authority:
(1) Conduct of audits related to oil and gas royalty payments made to the MMS which are attributable to leased Federal or Indian lands within the State. Delegations with respect to any Indian lands require the written permission, subject to the review of the MMS, of the affected Indian tribe or allottee.
(2) Conduct of investigations related to oil and gas royalty payments made to the MMS which are attributable to leased Federal lands or Indian lands within the State. Delegation with respect to any Indian lands require the written permission, subject to the review of the MMS, of the affected Indian tribe or allottee. No investigation will be initiated without the specific approval of the MMS or the Secretary's designee and in accordance with the Departmental Manual.
(b) The following authorities and responsibilities are specifically reserved to the MMS and are not delegable under these regulations:
(1) Enforcement actions to assess and collect additional royalties identified as a consequence of audits, inspections, and investigations. These include all actions related to resolution of royalty obligations so identified, and the establishment and maintenance of payment performance bonds which may be required during the resolution process.
(2) Enforcement actions to collect civil penalties and interest charges related to findings of audits, inspections, and investigations.
(3) Administration of all appeals and all actions of the Department related to administrative and judicial litigation.
(4) Issuance of subpoenas.
(c) The provisions of this section do not limit the authority provided to the States by section 204 of the Act.
(a) The governor or other authorized official of any State which contains Federal oil and gas leases, or Indian oil and gas leases where the Indian tribe and allottees have given the State an affirmative indication of their desire for the State to undertake certain royalty management-related activities on their lands, may petition the Secretary to assume responsibilities to conduct audits and related investigations of royalty related matters affecting Federal or Indian oil and gas leases within the State.
(b) A State may enter into a delegation of authority under this part without affecting a State's ability to enter into a cooperative agreement under Part 228 of this chapter.
(c) The Secretary shall carry out all factfinding and hearings he may decide are necessary in order to approve or disapprove the petition.
(d) In the event that the Secretary denies the petition, the Secretary must provide the State with the specific reasons for denial of the petition. The State will then have 60 days to either contest or correct specific deficiencies and to reapply for a delegation of authority.
(a) Upon receipt of a petition for delegation from a State, the Secretary shall appoint a representative to conduct a hearing or hearings to carry out factfinding and determine the ability of the petitioning State to carry out the delegated responsibilities requested in accordance with the provisions of this part.
(b) The Secretary's representative, after proper notice in the
(1) The State has an acceptable plan for carrying out delegated responsibilities and if it is likely that the State will provide adequate resources to achieve the purposes of this part (30 U.S.C. 1735);
(2) The State has the ability to put in place a process within 60 days of the grant of delegation which will assure the Secretary that the functions to be delegated to the State can be effectively carried out;
(3) The State has demonstrated that it will effectively and faithfully administer the rules and regulations of the Secretary in accordance with the requirements at 30 U.S.C. 1735;
(4) The State's plan to carry out the delegated authority will be in accordance with the MMS standards; and
(5) The State's plan to carry out the delegated authority will be coordinated with MMS and the Office of Inspector General audit efforts to eliminate added burden on any lessee or group of lessees operating Federal or Indian oil and gas leases within the State.
(c) A State petitioning for a delegation of authority shall be given the opportunity to present testimony at a public hearing.
(a) Delegations of authority shall be valid for a period of 3 years and may be renewable for an additional consecutive 3-year period upon request of the State and after the appropriate factfinding required in § 229.101. Delegations are subject to annual funding and the availability of appropriations specifically designated for the purpose of this part.
(b) A delegation of authority may be terminated at any time and upon any terms and conditions as mutually agreed upon by the parties.
(c) A State may terminate a delegation of authority by giving a 120-day written notice of intent to terminate.
(d) The Department may terminate a delegation of authority when it is determined, after opportunity for a hearing, that the State has failed to substantially comply with the provisions of the delegation of authority.
(e) No action to initiate formal hearing proceedings for termination shall be taken until the Department has notified the State in writing of alleged deficiencies and allowed the State 120 days to correct the deficiencies.
(f) Termination of a delegation shall not bar a subsequent request by a State to regain a delegation of authority.
Each delegation of authority under this part shall be in writing, shall incorporate all the requirements of this part, and shall specifically include:
(a) Terms obligating the State to conduct audit and investigative activities for a specific period of time;
(b) Terms describing the authorities and responsibilities reserved by the MMS, including, but not limited to, those specified under § 229.100;
(c) Terms requiring the State to provide annual audit workplans to include the lease universe by company, or by individual lease accounts, a description of the audit work product(s) to be delivered, and the State resources (staff and otherwise) to be committed to the delegation;
(d) Terms requiring the State to notify the MMS of any changed circumstances which would affect the State's ability to carry out the terms of the delegation;
(e) Terms requiring coordination of delegated activities among the State, the MMS, and the land management agencies responsible for management of the leases included in the audit universe;
(f) Terms requiring the State to maintain and make available to the MMS all audit workpapers, documents, and information gained or developed as a consequence of activities conducted under the delegation;
(g) Terms obligating the State to adhere to all Federal laws, rules and regulations, and Secretarial determinations and orders relating to the calculation, reporting, and payment of oil and gas royalties, in all activities performed under the delegation.
In the case of a State seeking a delegation of authority for Indian lands as
If at any time an Indian tribe or an individual Indian allottee determines that it wishes to withdraw from the State delegation of authority in relation to its lands, it may do so by sending a petition of withdrawal to the State. Once the petition has been received, the State shall within 30 days cease all activities being carried out under the delegation of authority on the lands covered by the petition for the tribe or allottee.
(a) The additional royalties and late payment charges resulting from State audit work done under a delegation of authority shall be collected by MMS. The State's share of any amounts so collected shall be paid to the State in accordance with the provisions of 30 U.S.C. 191 and part 219 of this chapter.
(b) Amounts collected for Indian leases shall be transferred to the appropriate Indian accounts (designated Treasury accounts) managed by the Bureau of Indian Affairs at the earliest practicable date after such funds are received, but in no case later than the last business day of the month in which such funds are received.
(c) MMS shall provide to the State on a monthly basis, an accounting of collections resulting from audit work and enforcement actions resulting from a delegation of authority. Such accounting will identify collections broken down by royalties, penalties and interest paid.
Fifty percent of any civil penalty resulting from activities under a delegation of authority shall be shared with the delegated State. However, the amount of the civil penalty shared will be deducted from any Federal funding owed under a delegation of authority under the provisions of 30 U.S.C. 1735. MMS shall maintain records of civil penalties collected and distributed to the States involved in 30 U.S.C. 1735 delegations. Each quarterly payment will be reduced by the amount of the civil penalties paid to the delegated State or tribe during the prior quarter.
(a) The Department of the Interior (DOI) shall reimburse the State for 100 percent of the direct cost associated with the activities undertaken under the delegation of authority. The State shall maintain books and records in accordance with the standards established by the DOI and will provide the DOI, on a quarterly basis, a summary of costs incurred for which the State is seeking reimbursement. Only costs as defined under the provisions of 30 U.S.C. 1735 are eligible for reimbursement.
(b) The State shall submit a voucher for reimbursement of costs incurred within 30 days of the end of each calendar quarter.
(a) The Department will carry out an annual examination of the State's delegated activities undertaken under the delegation of authority.
(b) The examination required by this section will consist of a management review and a fiscal examination and evaluation to determine—
(1) That activities being carried out by the State under the delegation of authority meet the standards established by the Department and in particular the provisions of 30 U.S.C. 1735; and
(2) That costs incurred by the State under the delegation of authority are eligible for reimbursement by the Department.
The MMS shall provide to the State all reports, files, and supporting materials within its possession necessary to allow the State to effectively carry out the terms of the delegation specified in § 229.104.
All activities performed by a State under a delegation must be in full accord with all Federal laws, rules and regulations, and Secretarial and agency determinations and orders relating to the calculation, reporting, and payment of oil and gas royalties. In those cases when guidance or interpretations are necessary, the State will direct written requests for such guidance or interpretation to the appropriate MMS officials. All policy and procedural guidance or interpretation provided by the MMS shall be in writing and shall be binding on the State.
(a) The State shall maintain in a safe and secure manner all records, workpapers, reports, and correspondence gained or developed as a consequence of audit or investigative activities conducted under the delegation. All such records shall be made available for review and inspection upon request by representatives of the Secretary and the Department's Office of Inspector General (OIG).
(b) The State must maintain in a confidential manner all data obtained from DOI sources or from payor or company sources under the delegation which have been deemed “confidential or proprietary” by DOI or a company or payor. In this regard, the State regulatory authority shall be bound by provisions of 30 U.S.C. 1733. MMS shall provide to the State guidelines for determining confidential and proprietary material.
(c) All records subject to the requirements of paragraph (a) must be maintained for a 6-year period measured from the end of the calendar year in which the records were created. All dispositions or records must be with the written approval of the MMS. Upon termination of a delegation, the State shall, within 90 days from the date of termination, assemble all records specified in subsection (a), complete all working paper files in accordance with § 229.124, and transfer such records to the MMS.
(d) The State shall maintain complete cost records for the delegation in accordance with generally accepted accounting principles. Such records shall be in sufficient detail to demonstrate the total actual costs associated with the project and to permit a determination by MMS whether delegation funds were used for their intended purpose. All such records shall be made available for review and inspection upon request by representatives of the Secretary and the Department's Office of Inspector General (OGIG).
(a) Each State with a delegation of authority shall submit annually to the MMS an audit workplan specifically identifying leases, resources, companies, and payors scheduled for audit. This workplan must be submitted 120 days prior to the beginning of each fiscal year. A State may request changes to its workplan (including the companies and leases to be audited) at the end of each quarter of each fiscal year. All requested changes are subject to approval by the MMS and must be submitted in writing.
(b) When a State plans to audit leases of a lessee or royalty payor for which
(c) The State shall consult with the MMS and/or OIG regarding resolution of any coordination problems encountered during the conduct of delegation activities.
(a) All audit activities performed under a delegation of authority must be in accordance with the “Standards for Audit of Governmental Organizations, Programs, Activities, and Functions” as issued by the Comptroller General of the United States.
(b) The following audit standards also shall apply to all audit work performed under a delegation of authority.
(1)
(ii)
(iii)
(iv)
(2)
(3)
(ii) A statement in the auditors’ report that the examination was made in accordance with the generally accepted program audit standards (including the applicable General Accounting Office (GAO) standards) for royalty compliance audits should be in the appropriate language to indicate that the audit was made in accordance with this statement of standards.
(iii) The auditor's report should contain a statement of positive assurance on those items tested and negative assurance on those items not tested. It should also include all instances of noncompliance and instances or indications of fraud, abuse, or illegal acts found during or in connection with the audit.
(iv) The auditor's report should contain any other material deficiency identified during the audit not covered in paragraph (b)(3)(iii) of this section.
(v) When factors external to the program and to the auditor restrict the audit or interfere with the auditor's ability to form objective opinions and conclusions (such as denial of access to
(vi) If certain information is prohibited from general disclosure, the auditor's report should state the nature of the information omitted and the requirement that makes the omission necessary.
(vii) Written audit reports are to be prepared in the format prescribed by the MMS.
(viii) In instances where the extent of the audit findings or the amounts involved do not warrant it, a formal audit report need not be issued. In lieu of an audit report, a memorandum of audit findings will be prepared and placed on the case file.
Every audit performed by a State under a delegation of authority must meet certain documentation standards. In particular, detailed workpapers must be developed and maintained.
(a)
(b) Each audit performed varies in scope and detail. As a result, the audit team must determine the best presentation of the workpapers for a particular audit. The following general standards of workpaper preparation are consistent with the goal of achieving proper documentation while maintaining sufficient flexibility.
(1) All relevant information obtained orally must be promptly recorded in writing and incorporated in the workpapers.
(2) Workpapers must be complete and accurate in order to provide support for findings and conclusions.
(3) Workpapers should be clear and understandable without the need for supplementary oral explanations. The information they contain must be clear, complete, and concise, so that anyone using the workpapers will be able to readily determine their purpose, the nature and scope of the work done, and the conclusions drawn.
(4) Workpapers must be legible and as neat as practicable. They must meet standards which allow their use as evidence in judicial and administrative proceedings.
(5) The information contained in workpapers should be restricted to matters which are materially important and relevant to the objectives established for the assignment.
(6) Workpapers must be in sufficient detail to permit a subsequent independent execution of each audit procedure, assuming the target company retains its accounting documentation.
(a) Determinations of additional royalties due resulting from audit activities conducted under a delegation of authority must be formally communicated by the State, to the companies or other payors by an issue letter prior to any enforcement action. The issue letter will serve to ensure that all audit findings are accurate and complete by obtaining advance comments from officials of the companies or payors audited. Issue letters must be prepared in a format specified by the MMS, and transmitted to the company or payor. The company or payor shall be given 30 days from receipt of the letter to respond to the State on the findings contained in the letter.
(b) After evaluating the company or payor's response to the issue letter, the State shall draft a demand letter which will be submitted with supporting workpaper files to the MMS for appropriate enforcement action. Any sustantive revisions to the demand letter will be discussed with the State prior to issuance of the letter. Copies of all enforcement action documents shall be provided to the State by MMS upon their issuance to the company or payor.
(a) Appeals made pursuant to the rules and procedures at 30 CFR parts 243 and 290 related to demand letters issued by officers of the MMS for additional royalties identified under a delegation of authority shall be filed with
(b) An affected State, upon the request of the MMS, shall provide expert witnesses from their audit staff for testimony as well as required documentation and analyses to support the Department's position during the litigation of court cases arising from denied appeals. The cost of providing expert witnesses including travel and per diem is reimbursable under the provisions of a delegation of authority, at the Federal Government's existing per diem rates.
The State, acting under the authority of the Secretarial delegation, shall submit quarterly reports which will summarize activities carried out by the State during the preceding quarter of the year under the provisions of the delegation. The report shall include:
(a) A statistical summary of the activities carried out, e.g., number of audits performed, accounts reconciled, and other actions taken;
(b) A summary of costs incurred during the previous quarter for which the State is seeking reimbursement; and
(c) A schedule of changes which the State proposes to make from its approved plan.
5 U.S.C. 301
(a) The amount of any refund or credit for any overpayment for any lease or leases governed by the Outer Continental Shelf Lands Act (OCSLA), as amended, for any production month shall not be reduced by offsetting against that overpayment any reported underpayment by the payor on any other lease or leases, except as provided in paragraph (b) of this section.
(b) Royalties attributed to production from a lease or leases governed by the OCSLA, which should have been attributed to production from a different lease or leases governed by the OCSLA, may be offset without regard to the provisions of OCSLA section 10, 43 U.S.C. 1339, only if the payor submits a written request to Minerals Management Service (MMS), Fiscal Accounting Division, for its approval of the correction and provides adequate documentation to show that the following conditions exist and are met:
(1) The error results from attributing and reporting an equal volume of production, produced from a lease or leases during a particular production month, to a different lease or leases from which that production was not produced for the same or another production month;
(2) The payor is the same for the lease or leases to which the production was attributed and the lease or leases to which it should have been attributed;
(3) The payor submits production reports, pipeline allocation reports, or other similar documentary evidence pertaining to the specific production involved which verifies the correct production information; and
(4) In the case of leases which are within the zone defined and governed by section 8(g) of the OCSLA, as amended, 43 U.S.C. 1337(g), the leases are located off the coast of the same State.
(c) If MMS approves a correction pursuant to paragraph (b) of this section, the payor is required to submit an adjusting royalty report (Form MMS-2014) pursuant to 30 CFR part 210 to correct its reporting to the Auditing and Financial System.
(d) If MMS requires a repayment of principal royalties or assesses late-payment interest as a result of the payor having improperly offset any underpayment against an overpayment and, therefore, having failed to request a refund or credit as required by section 10 of the OCSLA, 43 U.S.C. 1339, and the payor asserts pursuant to 30 CFR part 290 that some or all of the royalties or interest assessed is not owed pursuant to the exception set forth in paragraph (b) of this section, the burden is on the payor to demonstrate that the exception applies in the specific circumstances of the case.
(e) The exception set forth in paragraph (b) of this section shall not operate to relieve any payor of any liability imposed by statute or regulation for erroneous reporting.
This subpart establishes the procedures that lessees and other persons who make royalty and other payments on Federal oil and gas leases on the Outer Continental Shelf (OCS) must follow to recover certain excess payments made in connection with their leases in accordance with section 10 of the Outer Continental Shelf Lands Act (section 10), 43 U.S.C. 1339. The requirements of this subpart apply to both requests for refund from the Treasury of
Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.
(a) Except as otherwise provided in this subpart, no person may recover an excess payment it has made in connection with an OCS lease unless:
(1) That person has made a request for refund or credit in accordance with the provisions of this subpart;
(2) MMS has transmitted a report on the request for refund or credit to the President of the Senate and the Speaker of the House of Representatives and 30 days have expired since the submission in accordance with section 10(b), 43 U.S.C. 1339(b); and
(3) MMS notifies the person that its request for refund or credit is authorized and that the person may receive its refund for, or may report a credit adjustment to recoup, the excess payment.
(b) A request for refund or credit must:
(1) Be in writing;
(2) Provide the person's MMS-established payor code;
(3) Identify the leases and sales months with respect to which the excess payments occurred;
(4) Identify the amount of the excess payment or, with specificity, describe a class of payments that are, or as a result of an administrative or judicial decision or other identified contingency, may become, excess payments;
(5) Provide the reasons why a refund or credit is due;
(6) Include a certification that, to the best of the person's knowledge or belief, the information provided in response to paragraphs (b)(2) through (b)(5) of this section is accurate and complete.
(c) If MMS determines that a request for refund or credit is incomplete, the person who submitted the request will have 30 days, or such time as MMS may specify, following notice from MMS, to supplement the request for refund or credit.
(d) A credit adjustment reported on a Form MMS-2014 does not constitute a
(e) A person who has filed a request for refund or credit pursuant to this section may amend that request to add an additional amount if:
(1) The additional amount is for the same lease and sales month; and
(2) The reason for the excess payment for the additional amount is the same as for the originally requested amount.
(f) Except as otherwise provided in this subpart, no request for a refund or credit will be approved unless the request is received at MMS at the address provided below within 2 years of the date that MMS received the excess payment.
(1) The request for refund or credit must be received at the following address:
(i) By mail: Minerals Management Service, Section 10 Refund Requests, P.O. Box 173702, Denver, CO 80217-3702.
(ii) By express delivery or courier: Minerals Management Service, Section 10 Refund Requests, Building 85, Denver Federal Center, Room A-212, Denver, CO 80225.
(2) If the last day of the 2-year period from the date MMS received the excess payment falls on a Saturday, Sunday, holiday or any other day that MMS is not open for business at the address specified in paragraph (f)(1) of this section, then the last day of the 2-year period will be the next regular business day. Requests received at the specified MMS address after 4 p.m. Mountain Time are considered received the following business day.
No person is entitled to interest on any excess payment made in connection with a lease that is refunded or recouped pursuant to this subpart.
MMS may grant a refund or authorize a credit based upon satisfactory evidence that the payment for which a refund or credit is requested was made, and upon a determination that the payment was excess. An approved request for refund or credit may be subject to later review or audit by MMS. If, based upon later review or audit, MMS determines that the refund or credit should not have been granted or authorized, the person who requested the refund or credit must repay the amount refunded or recouped plus interest determined pursuant to 30 U.S.C. 1721(a) and 30 CFR 218.150 from the date the refund was made or the recoupment taken until the date it is repaid.
If a person makes an overpayment on any OCS lease or unit in a prior month, it may offset that overpayment against an underpayment that same person made in any prior month on that same lease or unit for the same or a different product without submitting a request for refund or credit. This offset is permitted only if the underpayment was not created as a result of a credit adjustment to recoup the amount of the overpayment or was not otherwise created intentionally to provide an underpayment against which to offset the overpayment. This offset also is subject to any limitations imposed by other applicable law or regulations.
(a) This section applies to any reallocation of production for a prior sales month among different persons who reported and paid royalty for that month on a lease or unit, except for reallocations of production that result from the approval or amendment of a unit agreement subject to § 230.461(b).
(b) In the event of a reallocation of production as described in paragraph (a) of this section, the respective persons who reported and paid royalty may reconcile any resulting differences in royalty payment obligations between themselves without submitting revised royalty reports or requests for refund or credit to MMS under this subpart, except that:
(1) Any person who paid any amount which remains as a net overpayment after such reconciliation must file a request for refund or credit in accordance
(2) Any person whose royalty obligation remains underpaid after such reconciliation must report the additional royalties due for the prior sales month on a Form MMS-2014 and pay interest on the underpayment from the last day of the month following the sales month until the date the additional royalties are paid; and
(3) All persons involved in such reconciliation must retain all documents pertaining to the reallocation of production, calculation of royalties due, and the subsequent reconciliation among the persons involved together with other records pertaining to production from that lease during the prior sales month and the royalty due and paid thereon, and make such documents available for review and audit in the same manner as other records pertaining to the lease.
(c) If persons who reported and paid royalty do not reconcile between themselves any differences in royalty payment obligations arising as a result of a reallocation as provided in paragraph (b) of this section, each person who pays royalties for the lease must report and pay any additional royalties due, or file a request for refund or credit in accordance with the requirements of this subpart to recover the excess payment, as applicable. Any person who reports additional royalties due for the prior sales month must pay interest pursuant to 30 CFR 218.54 on the underpayment from the last day of the month following the sales month until the date the additional royalties are paid.
(a) If a person reports a credit adjustment on Form MMS-2014 that results in a credit before MMS approves the recoupment pursuant to § 230.455, and if the credit adjustment does not qualify as one of the transactions not subject to section 10 as provided in § 230.461, then that person has taken an unauthorized credit adjustment.
(1) If the unauthorized credit adjustment recouped a payment that MMS received more than 2 years before the date MMS received the Form MMS-2014 which includes the unauthorized credit adjustment, the person must repay the amount recouped plus late payment interest determined pursuant to 30 U.S.C. 1721(a) and 30 CFR 218.150 from the date the unauthorized recoupment was taken until the date it is repaid. Unless the person filed a request for refund or credit pursuant to § 230.453 within 2 years of the making of the excess payment for which the unauthorized credit adjustment was reported, the excess payment is not subject to refund or recoupment.
(2) If the unauthorized credit adjustment recouped a payment that MMS received less than 2 years before the date MMS received the Form MMS-2014 with the unauthorized credit adjustment, the person must repay the amount recouped plus late payment interest determined pursuant to 30 U.S.C. 1721(a) and 30 CFR 218.150 from the date the unauthorized recoupment was taken until the date it is repaid. The report of the unauthorized credit adjustment on the Form MMS-2014 does not constitute a request for refund or credit that tolls the 2-year period in section 10(a), 43 U.S.C. 1339(a). The person may file a request for refund or credit pursuant to section 230.453 for the payment for which the unauthorized credit adjustment was reported. MMS will review the request pursuant to the requirements of this subpart only if the request for refund or credit is received within 2 years of the making of the original payment for which the unauthorized credit adjustment was reported.
(b) A person who reports an unauthorized credit adjustment to MMS on a Form MMS-2014 will be assessed $500 for each unauthorized credit adjustment reported.
(a) The period of 2 years from the making of the excess payment, within which a request for refund or credit must be filed under section 10(a), 43 U.S.C. 1339(a), will be:
(1) Tolled by MMS's receipt of a substantially complete request for refund or credit pursuant to § 230.453; or
(2) Tolled by a general tolling notice issued by MMS and published in the
(3) Stopped by an application for unitization of OCS leases with respect to any excess payment that may result from the reallocation of production among leases after the unit or revision is approved; or
(4) Tolled by a notice filed by a person at the address stated in § 230.453(f) stating that a specifically identified action or proceeding may result in payments made on an OCS lease becoming excess payments. The notice must include:
(i) A list of affected leases and sales months;
(ii) The specific action or proceeding that could result in payments becoming excess;
(iii) An estimate of the amount that could be subject to a request for refund or credit; and
(iv) The person's MMS-established payor code.
(b) A request for refund or credit that is filed timely by a person who made an excess payment on an OCS lease does not stop or toll the running of the 2-year period with respect to any excess payment made by any other person on that lease.
If MMS suspends an OCS lease pursuant to 30 CFR 250.10(b)(6), a person who has made excess rental payments for the period of suspension may request a refund or credit of any excess payments pursuant to this subpart. If the request for refund or credit is filed more than 2 years after MMS received the excess rentals, the excess payment will not be refunded, recouped, or credited against future rentals due on the same lease.
(a) A request for refund of, or any other action to recover, excess payments made by a refiner/purchaser under a royalty-in-kind contract for royalty oil produced from an OCS lease is not subject to section 10.
(b) If MMS approves a unit agreement on the OCS, or a revision to a unit, a person may file amended Forms MMS-2014 within the time period MMS prescribes, reallocating production among its affected leases. A person must file a request for refund or credit pursuant to this subpart only if, and to the extent that, there is a net reduction in the royalty that person previously paid for the leases committed to the unit as a result of the amendments.
(c) A person may amend Form MMS-2014 to adjust volume and royalty reports among OCS leases within a unit within the same sales month without filing a request for refund or credit pursuant to this subpart, except that a request for refund or credit must be filed to the extent that there is a net reduction in the royalty previously paid for the leases committed to the unit as a result of the amendments.
(d) A person who pays more money than the total royalty due as reported on the Form MMS-2014 accompanying the payment, where all amounts reported on the Form MMS-2014 are correct, may submit a request for refund of the overpaid amounts. The request for refund is not subject to section 10's requirements unless the Form MMS-2014 includes reports for only one OCS lease. Any overpayment subject to this paragraph may not be recovered by recoupment.
(e) A person may reduce an estimate balance, established for any lease product pursuant to MMS instructions, by submitting a credit adjustment on a Form MMS-2014, or a request for refund, for all or part of the established estimate balance. A credit adjustment or request for refund to recover all or part of an estimate balance authorized by this paragraph is not subject to the requirements of section 10.
(f)(1) If adjustment of an estimated oil transportation allowance or estimated gas transportation allowance pursuant to 30 CFR 206.105(e) and 206.157(e), respectively, results in an overpayment for any sales month because the estimated transportation costs were less than the actual costs, a person may submit a credit adjustment
(2) If adjustment of an estimated gas processing allowance pursuant to 30 CFR 206.159(e) results in an overpayment for any sales month because the estimated processing costs were less than the actual costs, a person may submit a credit adjustment on a Form MMS-2014 to recoup, or may request a refund of, the overpayment. The credit adjustment or request for refund authorized by this paragraph is not subject to the requirements of section 10, and MMS approval is not required before reporting the credit adjustment.
(3) If a person makes an error in the report of actual transportation or processing costs pursuant to paragraphs (f)(1) or (f)(2) of this section, any subsequent adjustment to the report that results in a credit is subject to section 10 and the requirements of this subpart.
(g) If a person pays pursuant to an MMS order and challenges the obligation to pay in an administrative appeal or judicial action, and if the person is successful in a challenge to all or part of the MMS order to pay, section 10 does not apply to the refund or recoupment of the disputed payment or portion thereof.
(h) MMS approval is not required for an adjustment by any person to the amount reported for a report month that results in a credit of not more than an amount established periodically by MMS and published in the
25 U.S.C. 396
The terms used in this subpart have the same meaning as in 30 U.S.C. 1702.
(a) If we believe that you have not followed any requirement of a statute, regulation, order, or terms of a lease for any Federal or Indian oil or gas lease, we may send you a Notice of Noncompliance telling you what the violation is and what you need to do to correct it to avoid civil penalties under 30 U.S.C. 1719(a) and (b).
(b) We will send the Notice to your address of record as shown in the following table:
(c) We will serve Notices of Noncompliance by using registered mail or personal service.
The matter will be closed if you correct all of the violations identified in the Notice of Noncompliance within 20 days after you receive the Notice (or within a longer time period specified in the Notice).
(a) We may send you a Notice of Civil Penalty if you do not correct all of the violations identified in the Notice of Noncompliance within 20 days after you receive the Notice of Noncompliance (or within a longer time period specified in that Notice). The Notice of Civil Penalty will tell you how much penalty you must pay. The penalty may be up to $500 per day, beginning with the date of the Notice of Noncompliance, for each violation identified in the Notice of Noncompliance for as long as you do not correct the violations.
(b) If you do not correct all of the violations identified in the Notice of Noncompliance within 40 days after you receive the Notice of Noncompliance (or 20 days following the expiration of a longer time period specified in that Notice), we may increase the penalty to up to $5,000 per day, beginning with the date of the Notice of Noncompliance, for each violation for as long as you do not correct the violations.
You may request a hearing on the record on a Notice of Noncompliance by filing a request within 30 days of the date you received the Notice of Noncompliance with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of the Interior, 4015 Wilson Boulevard, Arlington, Virginia 22203. You may do this regardless of whether you correct the violations identified in the Notice of Noncompliance.
(a) If you do not correct the violations identified in the Notice of Noncompliance, the penalties will continue to accrue even if you request a hearing on the record.
(b) You may petition the Hearings Division (Departmental) of the Office of Hearings and Appeals, to stay the accrual of penalties pending the hearing on the record and a decision by the Administrative Law Judge under § 241.72.
(1) You must file your petition within 45 calendar days of receiving the Notice of Noncompliance.
(2) To stay the accrual of penalties, you must post a bond or other surety instrument using the same standards and requirements as prescribed in 30 CFR part 243, subpart B, or demonstrate financial solvency using the same standards and requirements as prescribed in 30 CFR part 243, subpart C, for the principal amount of any unpaid amounts due that are the subject of the Notice of Noncompliance, including interest thereon, plus the amount of any penalties accrued before the date a stay becomes effective.
(3) The Hearings Division will grant or deny the petition under 43 CFR 4.21(b).
(a) You may request a hearing on the record to challenge only the amount of a civil penalty when you receive a Notice of Civil Penalty, if you did not previously request a hearing on the record under § 241.54. If you did not request a hearing on the record on the Notice of Noncompliance under § 241.54, you may not contest your underlying liability for civil penalties.
(b) You must file your request within 10 days after you receive the Notice of Civil Penalty with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of the Interior, 4015 Wilson Boulevard, Arlington, Virginia 22203.
The Federal Oil and Gas Royalty Management Act sets out several specific violations for which penalties accrue without an opportunity to first correct the violation.
(a) Under 30 U.S.C. 1719(c), you may be subject to penalties of up to $10,000 per day per violation for each day the violation continues if you:
(1) Knowingly or willfully fail to make any royalty payment by the date specified by statute, regulation, order or terms of the lease;
(2) Fail or refuse to permit lawful entry, inspection, or audit; or
(3) Knowingly or willfully fail or refuse to notify the Secretary, within 5 business days after any well begins production on a lease site or allocated to a lease site, or resumes production in the case of a well which has been off production for more than 90 days, of the date on which production has begun or resumed.
(b) Under 30 U.S.C. 1719(d), you may be subject to civil penalties of up to $25,000 per day for each day each violation continues if you:
(1) Knowingly or willfully prepare, maintain, or submit false, inaccurate, or misleading reports, notices, affidavits, records, data, or other written information;
(2) Knowingly or willfully take or remove, transport, use or divert any oil or gas from any lease site without having valid legal authority to do so; or
(3) Purchase, accept, sell, transport, or convey to another person, any oil or gas knowing or having reason to know that such oil or gas was stolen or unlawfully removed or diverted.
We will inform you of violations without a period to correct by issuing a Notice of Noncompliance explaining what the violation is and how to correct it. We also will send you a Notice of Civil Penalty stating the amount of the penalty. The Notice of Noncompliance and Notice of Civil Penalty may be issued simultaneously. We will send the Notice of Noncompliance and the Notice of Civil Penalty to your address of record under § 241.51(b) using the means of service specified under § 241.51(c).
You may request a hearing on the record of a Notice of Noncompliance regarding violations without a period to correct by filing a request within 30 days after you receive the Notice of Noncompliance with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of the Interior, 4015 Wilson Boulevard, Arlington, Virginia 22203. You may do this regardless of whether you correct the violations identified in the Notice of Noncompliance.
(a) If you do not correct the violations identified in the Notice of Noncompliance regarding violations without a period to correct, the penalties will continue to accrue even if you request a hearing on the record.
(b) You may ask the Hearings Division (Departmental) to stay the accrual of penalties pending the hearing
(1) You must file your petition within 45 calendar days after you receive the Notice of Noncompliance.
(2) To stay the accrual of penalties, you must post a bond or other surety instrument using the same standards and requirements as prescribed in 30 CFR part 243, subpart B, or demonstrate financial solvency using the same standards and requirements as prescribed in 30 CFR part 243, subpart C, for the principal amount of any unpaid amounts due that are the subject of the Notice of Noncompliance, including interest thereon, plus the amount of any penalties accrued before the date a stay becomes effective.
(3) The Hearings Division will grant or deny the petition under 43 CFR 4.21(b).
(a) You may request a hearing on the record to challenge only the amount of a civil penalty when you receive a Notice of Civil Penalty regarding violations without a period to correct, if you did not previously request a hearing on the record under § 241.62. If you did not request a hearing on the record on the Notice of Noncompliance under § 241.62, you may not contest your underlying liability for civil penalties.
(b) You must file your request within 10 days after you receive Notice of Civil Penalty with the Hearings Division (Departmental), Office of Hearings and Appeals, U.S. Department of the Interior, 4015 Wilson Boulevard, Arlington, Virginia 22203.
We determine the amount of the penalty by considering the severity of the violations, your history of compliance, and if you are a small business.
(a) The penalties under this part are in addition to interest you may owe on any underlying underpayments or unpaid debt.
(b) If you do not pay the penalty by the date required under § 241.75(d), MMS will assess you late payment interest on the penalty amount at the same rate interest is assessed under 30 CFR 218.54.
If you request a hearing on the record under §§ 241.54, 241.56, 241.62 or 241.64, the hearing will be conducted by a Departmental Administrative Law Judge from the Office of Hearings and Appeals. After the hearing, the Administrative Law Judge will issue a decision in accordance with the evidence presented and applicable law.
If you are adversely affected by the Administrative Law Judge's decision, you may appeal that decision to the Interior Board of Land Appeals under 43 CFR part 4, subpart E.
Under 30 U.S.C. 1719(j), you may seek judicial review of the decision of the Interior Board of Land Appeals. A suit for judicial review in the District Court will be barred unless filed within 90 days after the final order.
(a) You must pay the amount of the Notice of Civil Penalty issued under §§ 241.53 or 241.61, if you do not request a hearing on the record under § 241.54, § 241.56, § 241.62, or § 241.64.
(b) If you request a hearing on the record under § 241.54, § 241.56, § 241.62, or § 241.64, but you do not appeal the determination of the Administrative Law Judge to the Interior Board of Land Appeals under § 241.73, you must pay the amount assessed by the Administrative Law Judge.
(c) If you appeal the determination of the Administrative Law Judge to the Interior Board of Land Appeals, you must pay the amount assessed in the IBLA decision.
(d) You must pay the penalty assessed within 40 days after:
(1) You received the Notice of Civil Penalty, if you did not request a hearing on the record under either § 241.54, § 241.56, § 241.62, or § 241.64;
(2) You received an Administrative Law Judge's decision under § 241.72, if you obtained a stay of the accrual of penalties pending the hearing on the record under § 241.55(b) or § 241.63(b) and did not appeal the Administrative Law Judge's determination to the IBLA under § 241.73;
(3) You received an IBLA decision under § 241.73 if the IBLA continued the stay of accrual of penalties pending its decision and you did not seek judicial review of the IBLA's decision; or
(4) A final non-appealable judgment of a court of competent jurisdiction is entered, if you sought judicial review of the IBLA's decision and the Department or the appropriate court suspended compliance with the IBLA's decision pending the adjudication of the case.
(e) If you do not pay, that amount is subject to collection under the provisions of § 241.77.
Under 30 U.S.C. 1719(g), the Director or his or her delegate may compromise or reduce civil penalties assessed under this part.
(a) MMS may use all available means to collect the penalty including, but not limited to:
(1) Requiring the lease surety, for amounts owed by lessees, to pay the penalty;
(2) Deducting the amount of the penalty from any sums the United States owes to you; and
(3) Using judicial process to compel your payment under 30 U.S.C. 1719(k).
(b) If the Department uses judicial process, or if you seek judicial review under § 241.74 and the court upholds assessment of a penalty, the court shall have jurisdiction to award the amount assessed plus interest assessed from the date of the expiration of the 90-day period referred to in § 241.74. The amount of any penalty, as finally determined, may be deducted from any sum owing to you by the United States.
If you commit an act for which a civil penalty is provided at 30 U.S.C. 1719(d) and § 241.60(b), the United States may pursue criminal penalties as provided at 30 U.S.C. 1720, in addition to any authority for prosecution under other statutes.
5 U.S.C. 301
This part applies to you if you are a lessee or recipient of an order. This part explains:
(a) How you may suspend compliance with an order that you (or your designee if you are a lessee) have appealed under 30 CFR part 290 in effect prior to May 13, 1999 and contained in the 30 CFR, parts 200 to 699, edition revised as of July 1, 1998, or under 30 CFR part 290, subpart b; and
(b) When you or another person acting on your behalf must submit a bond or other surety or demonstrate financial solvency.
This part applies to all Federal mineral leases onshore and on the Outer Continental Shelf (OCS), and to all federally-administered mineral leases on Indian tribal and individual Indian mineral owners’ lands.
(1) The principal amount of any royalty, minimum royalty, rental, bonus, net profit share or proceed of sale;
(2) Any interest; or
(3) Any civil or criminal penalty.
(a) If you timely appeal an order, and if that order or portion of that order:
(1) Requires you to make a payment, and you want to suspend compliance with that order, you must post a bond or other surety instrument or demonstrate financial solvency under this part, except as provided in paragraph (b) of this section; or
(2) Does not require you to make a payment, compliance with that order is suspended when you meet all requirements to file that appeal.
(b) You need not meet the requirements of paragraph (a) of this section if:
(1) The order is an assessment; or
(2) Another person agrees to fulfill these requirements on your behalf under § 243.5.
Any other person, including a designee, payor, or affiliate, may post a bond or other surety instrument or demonstrate financial solvency under this part on behalf of an appellant required to post a bond or other surety instrument under § 243.4(a)(1).
If you must meet the bonding or financial solvency requirements under § 243.4(a)(1), or if another person is meeting your bonding or financial solvency requirements, then either you or the other person must post a bond or other surety instrument or demonstrate financial solvency within 60 days after you receive the order or the Notice of Order.
If you assume an appellant's responsibility to post a bond or other surety instrument or demonstrate financial solvency under § 243.5, you:
(a) Must notify MMS in writing at the address specified in § 243.200(a) that you are assuming the appellant's responsibility under this part;
(b) May not assert that you are not otherwise liable for royalties or other payments under 30 U.S.C. 1712(a), or any other theory, as a defense if MMS calls your bond or requires you to pay based on your demonstration of financial solvency; and
(c) May end your voluntarily-assumed responsibility for posting a bond or other surety instrument only after the appellant under this part either:
(1) Pays or posts a bond or other surety instrument; or
(2) Demonstrates financial solvency.
(a)
(1) If the amount under appeal is less than $10,000 or does not require payment of a specified amount, MMS will suspend your obligation to comply with the order. MMS will use the lease surety posted with the Bureau of Land Management for onshore leases, and MMS for OCS leases, as collateral for the obligation; or
(2) If the amount under appeal is $10,000 or more, MMS will suspend your obligation to comply with that order if you:
(i) Submit an MMS-specified surety instrument under subpart B of this part within a time period MMS prescribes; or
(ii) Demonstrate financial solvency under subpart C.
(b)
(1) If the amount under appeal is less than $1,000 or does not require payment, MMS will suspend your obligation to comply with the order. MMS will use the lease surety posted with the Bureau of Indian Affairs as collateral for the obligation; or
(2) If the amount under appeal is $1,000 or more, MMS will suspend your obligation to comply with that order if you submit an MMS-specified surety instrument under subpart B of this part within a time period MMS prescribes.
(c) Nothing in this part prohibits you from paying any demanded amount or complying with any other requirement pending appeal. However, voluntarily paying any demanded amount or otherwise complying with any other requirement when suspension of an order is otherwise available under these rules does not create judicially reviewable final agency action under 5 U.S.C. 704.
(d) Regardless of the amount under appeal, MMS may inform you that it will not suspend your obligation to comply with the order under paragraph (a) or (b) of this section because suspension would harm the interests of the United States or the Indian lessor.
(a) If you seek judicial review of an IBLA decision or other final action of the Department of the Interior regarding an order, MMS will suspend your obligation to comply with that order pending judicial review if you continue to meet the requirements of this part.
(b) Notwithstanding the provisions of paragraph (a) of this section, MMS may decide that it will not suspend your obligation to comply with an order. MMS will notify you in writing of that decision and the reasons for it.
(a) This section applies to you if, for an appeal of an order under this part, you:
(1) Maintain a bond or an MMS-specified surety instrument on your own behalf or for another person; or
(2) Have demonstrated financial solvency on your own behalf or for another person.
(b) MMS may initiate collection against the bond or other surety instrument or the person demonstrating financial solvency:
(1) If the MMS Director or the Deputy Commissioner of Indian Affairs decides your appeal adversely to you and you do not pay the amount due or appeal that decision to the IBLA under 43 CFR part 4, subpart E;
(2) If the IBLA, the Director of the Office of Hearings and Appeals, an Assistant Secretary, or the Secretary decides your appeal adversely to you, and you do not pay the amount due or pursue judicial review within 90 days of the decision;
(3) If a court of competent jurisdiction issues a final non-appealable decision adverse to you, and you do not pay the amount due within 30 days of the decision;
(4) If you do not increase the amount of your bond or other surety instrument as required under § 243.101(b), or otherwise fail to maintain an adequate surety instrument in effect, and you do not pay the amount due under the order within 30 days of notice from MMS under § 243.101(b);
(5) If the obligation to comply with an order or decision is not suspended under § 243.8 or § 243.9 and you do not pay the amount required under the order or decision; or
(6) If the MMS bond-approving officer determines that you are no longer financially solvent under § 243.202(c), and you do not pay the order amount or post a bond or other MMS-specified surety instrument under subpart B within 30 days of that determination.
Any decision on your surety amount under subpart B or your financial solvency under subpart C is final and is not subject to appeal.
If you appealed an order before June 14, 1999 and you submitted an MMS-specified surety instrument to suspend compliance with that order, you may replace the surety with a demonstration of financial solvency under this part at an administratively convenient time, such as when the surety instrument is due for renewal.
(a) An MMS-specified surety instrument must be in a form specified in MMS instructions. MMS will give you written information and standard forms for MMS-specified surety instrument requirements.
(b) MMS will use a bank-rating service to determine whether a financial institution has an acceptable rating to provide a surety instrument adequate to indemnify the lessor from loss or damage.
(1) Administrative appeal bonds must be issued by a qualified surety company which the Department of the Treasury has approved.
(2) Irrevocable letters of credit or certificates of deposit must be from a financial institution acceptable to MMS with a minimum 1-year period of coverage subject to automatic renewal up to 5 years.
(a) The MMS bond-approving officer may approve your surety if he or she determines that the amount is adequate to guarantee payment. The amount of your surety may vary depending on the form of the surety and how long the surety is effective.
(1) The amount of the MMS-specified surety instrument must include the principal amount owed under the order plus any accrued interest we determine is owed plus projected interest for a 1-year period.
(2) Treasury book-entry bond or note amounts must be equal to at least 120 percent of the required surety amount.
(b) If your appeal is not decided within 1 year from the filing date, you must increase the surety amount to cover additional estimated interest for another 1-year period. You must continue to do this annually on the date your appeal was filed. We will determine the additional estimated interest and notify you of the amount so you can amend your surety instrument.
(c) You may submit a single surety instrument that covers multiple appeals. You may change the instrument to add new amounts under appeal or remove amounts that have been adjudicated in your favor or that you have paid if you:
(1) Amend the single surety instrument annually on the date you filed your first appeal; and
(2) Submit a separate surety instrument for new amounts under appeal until you amend the instrument to cover the new appeals.
(a) To demonstrate financial solvency under this part, you must submit an audited consolidated balance sheet, and, if requested by the MMS bond-approving officer, up to 3 years of tax returns to the MMS, Debt Collection Section using:
(1) The U.S. Postal Service or private delivery at P.O. Box 5760, MS 3031, Denver, CO 80217-5760; or
(2) Courier or overnight delivery at MS 3031, Denver Federal Center, Bldg. 85, Room A-212, Denver, CO 80225-0165.
(b) You must submit an audited consolidated balance sheet annually, and, if requested, additional annual tax returns on the date MMS first determined that you demonstrated financial
(c) If you demonstrate financial solvency in the current calendar year, you are not required to redemonstrate financial solvency for new appeals of orders during that calendar year unless you file for protection under any provision of the U.S. Bankruptcy Code (Title 11 of the United States Code), or MMS notifies you that you must redemonstrate financial solvency.
(a) The MMS bond-approving officer will determine your financial solvency by examining your total net worth, including, as appropriate, the net worth of your affiliated entities.
(b) If your net worth, minus the amount we would require as surety under subpart B for all orders you have appealed is greater than $300 million, you are presumptively deemed financially solvent, and we will not require you to post a bond or other surety instrument.
(c) If your net worth, minus the amount we would require as surety under subpart B for all orders you have appealed is less than $300 million, you must submit the following to the MMS Debt Collection Section by one of the methods in § 243.200(a):
(1) A written request asking us to consult a business-information, or credit-reporting service or program to determine your financial solvency; and
(2) A nonrefundable $50 processing fee:
(i) You must pay the processing fee to us following the requirements for making payments found in 30 CFR 218.51. You are not required to use Electronic Funds Transfer (EFT) for these payments;
(ii) You must submit the fee with your request under paragraph (c)(1) of this section, and then annually on the date we first determined that you demonstrated financial solvency, as long as you are not able to demonstrate financial solvency under paragraph (a) of this section and you have active appeals.
(d) If you request that we consult a business-information or credit-reporting service or program under paragraph (c) of this section:
(1) We will use criteria similar to that which a potential creditor would use to lend an amount equal to the bond or other surety instrument we would require under subpart B;
(2) For us to consider you financially solvent, the business-information or credit-reporting service or program must demonstrate your degree of risk as low to moderate:
(i) If our bond-approving officer determines that the business-information or credit-reporting service or program information demonstrates your financial solvency to our satisfaction, our bond-approving officer will not require you to post a bond or other surety instrument under subpart B;
(ii) If our bond-approving officer determines that the business-information or credit-reporting service or program information does not demonstrate your financial solvency to our satisfaction, our bond-approving officer will require you to post a bond or other surety instrument under subpart B or pay the obligation.
(a) If you are presumptively financially solvent under § 243.201(b), MMS will determine your net worth as described under §§ 243.201(b) and (c) to evaluate your financial solvency at least annually on the date we first determined that you demonstrated financial solvency as long as you have active appeals and each time you appeal a new order.
(b) If you ask us to consult a business-information or credit-reporting service or program under § 243.201(c), we will consult a service or program annually as long as you have active appeals and each time you appeal a new order.
(c) If our bond-approving officer determines that you are no longer financially solvent, you must post a bond or other MMS-specified surety instrument under subpart B.
43 U.S.C. 1331,
The Secretary of the Interior (Secretary) authorized the Minerals Management Service (MMS) to regulate oil, gas, and sulphur exploration, development, and production operations on the outer Continental Shelf (OCS). Under the Secretary's authority, the Director requires that all operations:
(a) Be conducted according to the OCS Lands Act (OCSLA), the regulations in this part, MMS orders, the lease or right-of-way, and other applicable laws, regulations, and amendments; and
(b) Conform to sound conservation practice to preserve, protect, and develop mineral resources of the OCS to:
(1) Make resources available to meet the Nation's energy needs;
(2) Balance orderly energy resource development with protection of the human, marine, and coastal environments;
(3) Ensure the public receives a fair and equitable return on the resources of the OCS;
(4) Preserve and maintain free enterprise competition; and
(5) Minimize or eliminate conflicts between the exploration, development, and production of oil and natural gas and the recovery of other resources.
(a) 30 CFR part 250 contains the regulations of the MMS Offshore program that govern oil, gas, and sulphur exploration, development, and production operations on the OCS. When you conduct operations on the OCS, you must submit requests, applications, and notices, or provide supplemental information for MMS approval.
(b) The following table of general references shows where to look for information about these processes.
MMS may issue Notices to Lessees and Operators (NTLs) that clarify, supplement, or provide more detail about certain requirements. NTLs may also outline what you must provide as required information in your various submissions to MMS.
To appeal orders or decisions issued under MMS regulations in 30 CFR parts 250 to 282, follow the procedures in 30 CFR part 290.
Terms used in this part will have the meanings given in the Act and as defined in this section:
(1) The laws of which are declared, under section 4(a)(2) of the Act, to be the law of the United States for the portion of the OCS on which such activity is, or is proposed to be, conducted;
(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or installation or other device permanently or temporarily attached to the seabed;
(3) Which is receiving, or according to the proposed activity, will receive oil for processing, refining, or transshipment that was extracted from the OCS and transported directly to such State by means of vessels or by a combination of means including vessels;
(4) Which is designated by the Secretary as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the OCS; or
(5) In which the Secretary finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents to the marine or coastal environment in the event of any oil spill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities.
(1) Geophysical and geological (G&G) surveys using magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, coring, or other systems to detect or imply the presence of oil, gas, or sulphur; and
(2) Any drilling conducted for the purpose of searching for commercial quantities of oil, gas, and sulphur, including the drilling of any additional well needed to delineate any reservoir to enable the lessee to decide whether to proceed with development and production.
(1) As used in § 250.130, any installation permanently or temporarily attached to the seabed on the OCS (including manmade islands and bottom-sitting structures). It includes mobile
(2) As used in § 250.303, means any installation or device permanently or temporarily attached to the seabed. It includes mobile offshore drilling units (MODUs), even while operating in the “tender assist” mode (i.e. with skid-off drilling units) or other vessels engaged in drilling or downhole operations. They are used for exploration, development, and production activities for oil, gas, or sulphur and emit or have the potential to emit any air pollutant from one or more sources. During production, multiple installations or devices are a single facility if the installations or devices are at a single site. Any vessel used to transfer production from an offshore facility is part of the facility while it is physically attached to the facility.
(3) As used in § 250.417(b), means a vessel, a structure, or an artificial island used for drilling, well-completion, well-workover, and/or production operations.
(1) Drilling, logging, coring, testing, or producing operations have confirmed the absence of H
(2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an absence of H
(1) The boundaries of a single lease or unit, but are not owned and operated by a lessee or operator of that lease or unit;
(2) The boundaries of contiguous (not cornering) leases that do not have a common lessee or operator;
(3) The boundaries of contiguous (not cornering) leases that have a common lessee or operator but are not owned and operated by that common lessee or operator; or
(4) An unleased block(s).
(1) Cutting paraffin;
(2) Removing and setting pump-through-type tubing plugs, gas-lift valves, and subsurface safety valves that can be removed by wireline operations;
(3) Bailing sand;
(4) Pressure surveys;
(5) Swabbing;
(6) Scale or corrosion treatment;
(7) Caliper and gauge surveys;
(8) Corrosion inhibitor treatment;
(9) Removing or replacing subsurface pumps;
(10) Through-tubing logging (diagnostics);
(11) Wireline fishing;
(12) Setting and retrieving other subsurface flow-control devices; and
(13) Acid treatments.
(1) The physical waste of oil, gas, or sulphur;
(2) The inefficient, excessive, or improper use, or the unnecessary dissipation of reservoir energy;
(3) The locating, spacing, drilling, equipping, operating, or producing of any oil, gas, or sulphur well(s) in a manner that causes or tends to cause a reduction in the quantity of oil, gas, or sulphur ultimately recoverable under prudent and proper operations or that causes or tends to cause unnecessary or excessive surface loss or destruction of oil or gas; or
(4) The inefficient storage of oil.
The Director will regulate all operations under a lease, right-of-use and easement, or right-of-way to:
(a) Promote orderly exploration, development, and production of mineral resources;
(b) Prevent injury or loss of life;
(c) Prevent damage to or waste of any natural resource, property, or the environment; and
(d) Cooperate and consult with affected States, local governments, other interested parties, and relevant Federal agencies.
(a) You must protect health, safety, property, and the environment by:
(1) Performing all operations in a safe and workmanlike manner; and
(2) Maintaining all equipment in a safe condition.
(b) You must immediately control, remove, or otherwise correct any hazardous oil and gas accumulation or other health, safety, or fire hazard.
(c) You must use the best available and safest technology (BAST) whenever practical on all exploration, development, and production operations. In general, we consider your compliance with MMS regulations to be the use of BAST.
(d) The Director may require additional measures to ensure the use of BAST:
(1) To avoid the failure of equipment that would have a significant effect on safety, health, or the environment;
(2) If it is economically feasible; and
(3) If the benefits outweigh the costs.
(a) If you operate a crane installed on fixed platforms you must:
(1) Follow the American Petroleum Institute (API) Recommended Practice (RP) for Operation and Maintenance of Offshore Cranes (API RP 2D);
(2) Keep inspection, testing, and maintenance records at the OCS facility for at least 2 years; and
(3) Keep crane operator qualifications at the facility for at least 4 years.
(b) You must operate and maintain all other material-handling equipment in a manner that ensures safe operations and prevents pollution.
(a) You must submit a Welding Plan to the District Supervisor before you begin drilling or production activities on a lease. You may not begin welding until the District Supervisor has approved your plan.
(b) You must keep the following at the site where welding occurs:
(1) A copy of the plan and its approval letter; and
(2) Drawings showing the designated safe-welding areas.
You must include all of the following in the Welding Plan that you prepare under § 250.109:
(a) Standards or requirements for welders;
(b) How you will ensure that only qualified personnel weld;
(c) Practices and procedures for safe welding that address:
(1) Welding in designated safe areas;
(2) Welding in undesignated areas, including wellbay;
(3) Fire watches;
(4) Maintenance of welding equipment; and
(5) Plans showing all designated safe-welding areas.
(d) How you will prevent spark-producing activities (i.e., grinding, abrasive blasting/cutting and arc-welding) in hazardous locations.
A welding supervisor or a designated person in charge must be thoroughly familiar with your welding plan. This person must ensure that each welder is properly qualified according to the welding plan. This person also must inspect all welding equipment before welding.
Your welding equipment must meet the following requirements:
(a) All engine-driven welding equipment must be equipped with spark arrestors and drip pans;
(b) Welding leads must be completely insulated and in good condition;
(c) Hoses must be leak-free and equipped with proper fittings, gauges, and regulators; and
(d) Oxygen and fuel gas bottles must be secured in a safe place.
(a) Before you weld, you must move any equipment containing hydrocarbons or other flammable substances at least 35 feet horizontally from the welding area. You must move similar equipment on lower decks at least 35 feet from the point of impact where slag, sparks, or other burning materials could fall. If moving this equipment is impractical, you must protect that equipment with flame-proofed covers, shield it with metal or fire-resistant guards or curtains, or render the flammable substances inert.
(b) While you weld, you must monitor all water-discharge-point sources from hydrocarbon-handling vessels. If a discharge of flammable fluids occurs, you must stop welding.
(c) If you cannot weld in one of the designated safe-welding areas that you listed in your safe welding plan, you must meet the following requirements:
(1) You may not begin welding until:
(i) The welding supervisor or designated person in charge advises in writing that it is safe to weld.
(ii) You and the designated person in charge inspect the work area and areas below it for potential fire and explosion hazards.
(2) During welding, the person in charge must designate one or more persons as a fire watch. The fire watch must:
(i) Have no other duties while actual welding is in progress;
(ii) Have usable firefighting equipment;
(iii) Remain on duty for 30 minutes after welding activities end; and
(iv) Maintain a continuous surveillance with a portable gas detector during the welding and burning operation if welding occurs in an area not equipped with a gas detector.
(3) You may not weld piping, containers, tanks, or other vessels that have contained a flammable substance unless you have rendered the contents inert and the designated person in charge has determined it is safe to weld. This does not apply to approved hot taps.
(4) You may not weld within 10 feet of a wellbay unless you have shut in all producing wells in that wellbay.
(5) You may not weld within 10 feet of a production area, unless you have shut in that production area.
(6) You may not weld while you drill, complete, workover, or conduct wireline operations unless:
(i) The fluids in the well (being drilled, completed, worked over, or having wireline operations conducted) are noncombustible; and
(ii) You have precluded the entry of formation hydrocarbons into the wellbore by either mechanical means
The requirements in this section apply to all electrical equipment on all platforms, artificial islands, fixed structures, and their facilities.
(a) You must classify all areas according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2.
(b) Employees who maintain your electrical systems must have expertise in area classification and the performance, operation and hazards of electrical equipment.
(c) You must install all electrical systems according to API RP 14F, Recommended Practice for Design and Installation of Electrical Systems for Offshore Production Platforms. You do not have to comply with Sections 7.4, Emergency Lighting, and 9.4, Aids to Navigation Equipment.
(d) On each engine that has an electric ignition system, you must use an ignition system designed and maintained to reduce the release of electrical energy.
You must follow the procedures in this section to determine well producibility if your well is not in the GOM. If your well is in the GOM you must follow the procedures in either this section or in § 250.116 of this subpart.
(a) You must write to the Regional Supervisor asking for permission to determine producibility.
(b) You must either:
(1) Allow the District Supervisor to witness each test that you conduct under this section; or
(2) Receive the District Supervisor's prior approval so that you can submit either test data with your affidavit or third party test data.
(c) If the well is an oil well, you must conduct a production test that lasts at least 2 hours after flow stabilizes.
(d) If the well is a gas well, you must conduct a deliverability test that lasts at least 2 hours after flow stabilizes, or a four-point back pressure test.
If your well is in the GOM, you must follow either the procedures in § 250.115 of this subpart or the procedures in this section to determine producibility.
(a) You must write to the Regional Supervisor asking for permission to determine producibility.
(b) You must provide or make available to the Regional Supervisor, as requested, the following log, core, analyses, and test criteria that MMS will consider collectively:
(1) A log showing sufficient porosity in the producible section.
(2) Sidewall cores and core analyses that show that the section is capable of producing oil or gas.
(3) Wireline formation test and/or mud-logging analyses that show that the section is capable of producing oil or gas.
(4) A resistivity or induction electric log of the well showing a minimum of 15 feet (true vertical thickness except for horizontal wells) of producible sand in one section.
(c) No section that you count as producible under paragraph (b)(4) of this section may include any interval that appears to be water saturated.
(d) Each section you count as producible under paragraph (b)(4) of this section must exhibit:
(1) A minimum true resistivity ratio of the producible section to the nearest clean or water-bearing sand of at least 5:1; and
(2) One of the following:
(i) Electrical spontaneous potential exceeding 20-negative millivolts beyond the shale baseline; or
(ii) Gamma ray log deflection of at least 70 percent of the maximum gamma ray deflection in the nearest
A determination of well producibility invokes minimum royalty status on the lease as provided in 30 CFR 202.53.
The Regional Supervisor may authorize you to inject gas on the OCS, on and off-lease, to promote conservation of natural resources and to prevent waste.
(a) To receive MMS approval for injection, you must:
(1) Show that the injection will not result in undue interference with operations under existing leases; and
(2) Submit a written application to the Regional Supervisor for injection of gas.
(b) The Regional Supervisor will approve gas injection applications that:
(1) Enhance recovery;
(2) Prevent flaring of casinghead gas; or
(3) Implement other conservation measures approved by the Regional Supervisor.
The Regional Supervisor may authorize subsurface storage of gas on the OCS, on and off-lease, for later commercial benefit. To receive MMS approval you must:
(a) Show that the subsurface storage of gas will not result in undue interference with operations under existing leases; and
(b) Sign a storage agreement that includes the required payment of a storage fee or rental.
(a) If you produce gas from an OCS lease and inject it into a reservoir on the lease or unit for the purposes cited in § 250.118(b), you are not required to pay royalties until you remove or sell the gas from the reservoir.
(b) If you produce gas from an OCS lease and store it according to § 250.119, you must pay royalty before injecting it into the storage reservoir.
(c) If you produce gas from an OCS lease and treat it at an off-lease or off-unit location, you must pay royalties when the gas is first produced.
If the reservoir contains both original gas in place and injected gas, when you produce gas from the reservoir you must use an MMS-approved formula to determine the amounts of injected or stored gas and gas original to the reservoir.
If you use a lease area for subsurface storage of gas, it does not affect the continuance or expiration of the lease.
You may not store gas on unleased lands unless the Regional Supervisor approves a right-of-use and easement for that purpose, under §§ 250.160 through 250.166 of this subpart.
To receive the Regional Supervisor's approval to inject gas into the cap rock of a salt dome containing a sulphur deposit, you must show that the injection:
(a) Is necessary to recover oil and gas contained in the cap rock; and
(b) Will not significantly increase potential hazards to present or future sulphur mining operations.
MMS will inspect OCS facilities and any vessels engaged in drilling or other downhole operations. These include facilities under jurisdiction of other Federal agencies that we inspect by agreement. We conduct these inspections:
(a) To verify that you are conducting operations according to the Act, the
(b) To determine whether equipment designed to prevent or ameliorate blowouts, fires, spillages, or other major accidents has been installed and is operating properly according to the requirements of this part.
MMS conducts both scheduled and unscheduled inspections.
(a) When MMS conducts an inspection, you must provide:
(1) Access to all platforms, artificial islands, and other installations on your leases or associated with your lease, right-of-use and easement, or right-of-way; and
(2) Helicopter landing sites and refueling facilities for any helicopters we use to regulate offshore operations.
(b) You must make the following available for us to inspect:
(1) The area covered under a lease, right-of-use and easement, right-of-way, or permit;
(2) All improvements, structures, and fixtures on these areas; and
(3) All records of design, construction, operation, maintenance, repairs, or investigations on or related to the area.
Upon request, MMS will reimburse you for food, quarters, and transportation that you provide for MMS representatives while they inspect lease facilities and operations. You must send us your reimbursement request within 90 days of the inspection.
If your operating performance is unacceptable, MMS may disapprove or revoke your designation as operator on a single facility or multiple facilities. We will give you adequate notice and opportunity for a review by MMS officials before imposing a disqualification.
In determining if your operating performance is unacceptable, MMS will consider, individually or collectively:
(a) Accidents and their nature;
(b) Pollution events, environmental damages and their nature;
(c) Incidents of noncompliance;
(d) Civil penalties;
(e) Failure to adhere to OCS lease obligations; or
(f) Any other relevant factors.
When you apply for MMS approval of any activity, we normally give you a written decision. The following table shows circumstances under which we may give an oral approval.
You may use alternate procedures or equipment after receiving approval as described in this section.
(a) Any alternate procedures or equipment that you propose to use must provide a level of safety and environmental protection that equals or surpasses current MMS requirements.
(b) You must receive the District or Regional Supervisor's written approval before you can use alternate procedures or equipment.
(c) To receive approval, you must either submit information or give an oral presentation to the appropriate Supervisor. Your presentation must describe the site-specific application(s), performance characteristics, and safety features of the proposed procedure or equipment.
We may approve departures to the operating requirements. You may apply for a departure by writing to the District or Regional Supervisor.
(a) You must provide the Regional Supervisor an executed Designation of Operator form unless you are the only lessee and are the only person conducting lease operations. When there is more than one lessee, each lessee must submit the Designation of Operator form and the Regional Supervisor must approve the designation before the designated operator may begin operations on the leasehold.
(b) This designation is authority for the designated operator to act on your behalf and to fulfill your obligations under the Act, the lease, and the regulations in this part.
(c) You, or your designated operator, must immediately provide the Regional Supervisor a written notification of any change of address.
(a) When a Designation of Operator terminates, the Regional Supervisor must approve a new designated operator before you may continue operations. Each lessee must submit a new executed Designation of Operator form.
(b) If your Designation of Operator is terminated, or a controversy develops between you and your designated operator, you and your designated operator must protect the lessor's interests.
(a) You or your designated operator may designate for the Regional Supervisor's approval, or the Regional Director may require you to designate an agent empowered to fulfill your obligations under the Act, the lease, or the regulations in this part.
(b) You or your designated operator may designate for the Regional Supervisor's approval a local agent empowered to receive notices and submit requests, applications, notices, or supplemental information.
(a) When you are not the sole lessee, you and your co-lessee(s) are jointly and severally responsible for fulfilling your obligations under the provisions of 30 CFR parts 250 through 282, unless otherwise provided in these regulations.
(b) If your designated operator fails to fulfill any of your obligations under 30 CFR parts 250 through 282, the Regional Supervisor may require you or any or all of your co-lessees to fulfill those obligations or other operational obligations under the Act, the lease, or the regulations.
(c) Whenever the regulations in 30 CFR parts 250 through 282 require the lessee to meet a requirement or perform an action, the lessee, operator (if one has been designated), and the person actually performing the activity to which the requirement applies are jointly and severally responsible for complying with the regulation.
(a) Assign each facility a letter designation except for those types of facilities identified in paragraph (c)(1) of this section. For example, A, B, CA, or CB.
(1) After a facility is installed, rename each predrilled well that was assigned only a number and was suspended temporarily at the mudline or at the surface. Use a letter and number designation. The letter used must be the same as that of the production facility, and the number used must correspond to the order in which the well was completed, not necessarily the number assigned when it was drilled. For example, the first well completed for production on Facility A would be renamed Well A-1, the second would be Well A-2, and so on; and
(2) When you have more than one facility on a block, each facility installed, and not bridge-connected to another facility, must be named using a different letter in sequential order. For example, EC 222A, EC 222B, EC 222C.
(3) When you have more than one facility on multiple blocks in a local area being co-developed, each facility installed and not connected with a walkway to another facility should be named using a different letter in sequential order with the block number corresponding to the block on which the platform is located. For example, EC 221A, EC 222B and EC 223C.
(b) In naming multiple well caissons, you must assign a letter designation.
(c) In naming single well caissons, you must use certain criteria as follows:
(1) For single well caissons not attached to a facility with a walkway, use the well designation. For example, Well No. 1;
(2) For single well caissons attached to a facility with a walkway, use the same designation as the facility. For example, rename Well No.10 as A-10; and
(3) For single well caissons with production equipment, use a letter designation for the facility name and a letter plus number designation for the well. For example, the Well No. 1 caisson would be designated as Facility A, and the well would be Well A-1.
The operator assigns a name to the facility.
Facilities will be named and identified according to the Regional Director's directions.
You do not have to rename facilities installed and wells drilled before January 27, 2000, unless the Regional Director requires it.
(a) You must identify all facilities, artificial islands, and mobile offshore drilling units with a sign maintained in a legible condition.
(1) You must display an identification sign that can be viewed from the waterline on at least one side of the platform. The sign must use at least 3-inch letters and figures.
(2) When helicopter landing facilities are present, you must display an additional identification sign that is visible from the air. The sign must use at least 12-inch letters and figures and must also display the weight capacity of the helipad unless noted on the top of the helipad. If this sign is visible to both helicopter and boat traffic, then the sign in paragraph (a)(1) of this section is not required.
(3) Your identification sign must:
(i) List the name of the lessee or designated operator;
(ii) In the GOM OCS Region, list the area designation or abbreviation and the block number of the facility location as depicted on OCS Official Protraction Diagrams or leasing maps;
(iii) In the Pacific OCS Region, list the lease number on which the facility is located; and
(iv) List the name of the platform, structure, artificial island, or mobile offshore drilling unit.
(b) You must identify singly completed wells and multiple completions as follows:
(1) For each singly completed well, list the lease number and well number on the wellhead or on a sign affixed to the wellhead;
(2) For wells with multiple completions, downhole splitter wells, and multilateral wells, identify each completion in addition to the well name and lease number individually on the well flowline at the wellhead; and
(3) For subsea wells that flow individually into separate pipelines, affix the required sign on the pipeline or surface flowline dedicated to that subsea well at a convenient location on the receiving platform. For multiple subsea wells that flow into a common pipeline or pipelines, no sign is required.
MMS may grant you a right-of-use and easement on leased and unleased lands on the OCS, if you meet these requirements:
(a) You must need the right-of-use and easement to construct and maintain platforms, artificial islands, and installations and other devices at an OCS site other than an OCS lease you own, that are:
(1) Permanently or temporarily attached to the seabed; and
(2) Used for conducting exploration, development, and production activities or other operations on or off lease; or
(3) Used for other purposes approved by MMS.
(b) You must exercise the right-of-use and easement according to the regulations of this part;
(c) You must meet the requirements at 30 CFR 256.35 (Qualification of lessees); establish a regional Company File as required by MMS; and must meet bonding requirements;
(d) If you apply for a right-of-use and easement on a leased area, you must notify the lessee and give her/him an opportunity to comment on your application; and
(e) You must receive MMS approval for all platforms, artificial islands, and installations and other devices permanently or temporarily attached to the seabed.
With your application, you must describe the proposed use giving:
(a) Details of the proposed uses and activities including access needs and special rights of use that you may need;
(b) A description of all facilities for which you are seeking authorization;
(c) A map or plat describing primary and alternate project locations; and
(d) A schedule for constructing any new facilities, drilling or completing any wells, anticipated production rates, and productive life of existing production facilities.
If your right-of-use and easement is on a lease, you may continue to exercise the right-of-use and easement after the lease on which it is situated terminates. You must only use the right-of-use and easement for the purpose that the grant specifies. All future lessees of that portion of the OCS on which your right-of-use and easement is situated must continue to recognize the right-of-use and easement for the purpose that the grant specifies.
(a) MMS may grant a lessee of a State lease located adjacent to or accessible from the OCS a right-of-use and easement on the OCS.
(b) MMS will only grant a right-of-use and easement under this paragraph to enable a State lessee to conduct and maintain a device that is permanently or temporarily attached to the seabed (i.e., a platform, artificial island, or installation). The lessee must use the device to explore for, develop, and produce oil and gas from the adjacent or accessible State lease and for other operations related to these activities.
(a) A right-of-use and easement granted under the heading of “Right-of-use and easement” in this subpart is subject to MMS regulations, 30 CFR parts 250 through 282, and any terms and conditions that the Regional Director prescribes.
(b) For the whole or fraction of the first calendar year, and annually after that, you must pay to MMS, in advance, an annual rental payment.
When you apply for a right-of-use and easement, you must pay:
(a) A nonrefundable filing fee as specified in § 0.1010(a); and
(b) The first year's rental as specified in § 250.1009(c)(2).
(a) Before MMS issues you a right-of-use and easement on the OCS, you must furnish the Regional Director a surety bond for $500,000.
(b) The Regional Director may require additional security from you (i.e., security above the prescribed $500,000) to cover additional costs and liabilities for regulatory compliance. This additional surety:
(1) Must be in the form of a supplemental bond or bonds meeting the requirements of § 256.54 (General requirements for bonds) or an increase in the coverage of an existing surety bond.
(2) Covers additional costs and liabilities for regulatory compliance, including well abandonment, platform and structure removal, and site clearance from the seafloor of the right-of-use and easement.
(a) You may request approval of a suspension, or the Regional Supervisor may direct a suspension (Directed Suspension), for all or any part of a lease or unit area.
(b) Depending on the nature of the suspended activity, suspensions are labeled either Suspensions of Operations (SOO) or Suspensions of Production (SOP).
(a) A suspension may extend the term of a lease (see § 250.180(b)). The extension is equal to the length of time the suspension is in effect, except as provided in paragraph (b) of this section.
(b) A Directed Suspension does not extend the term of a lease when the Regional Supervisor
(1) Gross negligence; or
(2) A willful violation of a provision of the lease or governing statutes and regulations.
(a) MMS may issue suspensions for up to 5 years per suspension. The Regional Supervisor will set the length of the suspension based on the conditions of the individual case involved. MMS may grant consecutive suspension periods.
(b) An SOO ends automatically when the suspended operation commences.
(c) An SOP ends automatically when production begins.
(d) A Directed Suspension normally ends as specified in the letter directing the suspension.
(e) MMS may terminate any suspension when the Regional Supervisor determines the circumstances that justified the suspension no longer exist or that other lease conditions warrant termination. The Regional Supervisor will notify you of the reasons for termination and the effective date.
You must submit your request for a suspension to the Regional Supervisor, and MMS must receive the request before the end of the lease term (i.e., end of primary term, end of the 180-day period following the last leaseholding operation, and end of a current suspension).
(a) The justification for the suspension including the length of suspension requested;
(b) A reasonable schedule of work leading to the commencement or restoration of the suspended activity;
(c) A statement that a well has been drilled on the lease and determined to be producible according to §§ 250.115, 250.116, or 250.1603 (SOP only); and
(d) A commitment to production (SOP only).
The Regional Supervisor may grant or direct an SOO or SOP under any of the following circumstances:
(a) When necessary to comply with judicial decrees prohibiting any activities or the permitting of those activities. The effective date of the suspension will be the effective date required by the action of the court;
(b) When activities pose a threat of serious, irreparable, or immediate harm or damage. This would include a threat to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment. MMS may require you to do a site-specific study. (See § 250.177(a).)
(c) When necessary for the installation of safety or environmental protection equipment;
(d) When necessary to carry out the requirements of NEPA or to conduct an environmental analysis; or
(e) When necessary to allow for inordinate delays encountered in obtaining required permits or consents, including administrative or judicial challenges or appeals.
The Regional Supervisor may direct a suspension when:
(a) You failed to comply with an applicable law, regulation, order, or provision of a lease or permit; or
(b) The suspension is in the interest of national security or defense.
The Regional Supervisor may grant or direct an SOP when the suspension is in the national interest, and it is necessary because the suspension will meet one of the following criteria:
(a) It will allow you to properly develop a lease, including time to construct and install production facilities;
(b) It will allow you time to obtain adequate transportation facilities;
(c) It will allow you time to enter a sales contract for oil, gas, or sulphur. You must show that you are making an effort to enter into the contract(s); or
(d) It will avoid continued operations that would result in premature abandonment of a producing well(s).
The Regional Supervisor may grant an SOO when necessary to allow you time to begin drilling or other operations when you are prevented by reasons beyond your control, such as unexpected weather, unavoidable accidents, or drilling rig delays.
A directed suspension may affect the payment of rental or royalties for the lease as provided in § 218.154.
If MMS grants or directs a suspension under paragraph § 250.172(b), the Regional Supervisor may require you to:
(a) Conduct a site-specific study.
(1) The Regional Supervisor must approve or prescribe the scope for any site-specific study that you perform.
(2) The study must evaluate the cause of the hazard, the potential damage, and the available mitigation measures.
(3) You must pay for the study unless you request, and the Regional Supervisor agrees to arrange, payment by another party.
(4) You must furnish copies and results of the study to the Regional Supervisor.
(5) MMS will make the results available to other interested parties and to the public.
(6) The Regional Supervisor will use the results of the study and any other information that becomes available:
(i) To decide if the suspension can be lifted; and
(ii) To determine any actions that you must take to mitigate or avoid any damage to the environment, life, or property.
(b) Submit a revised Exploration Plan (including any required mitigating measures);
(c) Submit a revised Development and Production Plan (including any required mitigating measures); or
(d) Submit a revised Development Operations Coordination Document according to 30 CFR Part 250, subpart B.
(a) If your lease is in its primary term:
(1) You must submit a report to the District Supervisor according to paragraphs (h) and (i) of this section whenever production begins initially, whenever production ceases during the last 180 days of the primary term, and whenever production resumes during the last 180 days of the primary term.
(2) Your lease expires at the end of its primary term unless you are conducting operations on your lease (see 30 CFR part 256). For purposes of this section, the term
(b) If you stop conducting operations during the last 180 days of your primary lease term, your lease will expire unless you either resume operations or receive an SOO or an SOP from the Regional Supervisor under §§ 250.172, 250.173, 250.174, or 250.175 before the end of the 180th day after you stop operations.
(c) If you extend your lease term under paragraph (b) of this section, you must pay rental or minimum royalty, as appropriate, for each year or part of the year during which your lease continues in force beyond the end of the primary lease term.
(d) If you stop conducting operations on a lease that has continued beyond its primary term, your lease will expire unless you resume operations or receive an SOO or an SOP from the Regional Supervisor under § 250.172, 250.173, 250.174, or 250.175 before the end of the 180th day after you stop operations.
(e) You may ask the Regional Supervisor to allow you more than 180 days to resume operations on a lease continued beyond its primary term when operating conditions warrant. The request must be in writing and explain the operating conditions that warrant a longer period. In allowing additional time, the Regional Supervisor must determine that the longer period is in the national interest, and it conserves resources, prevents waste, or protects correlative rights.
(f) When you begin conducting operations on a lease that has continued beyond its primary term, you must immediately notify the District Supervisor either orally or by fax or e-mail and follow up with a written report according to paragraph (g) of this section.
(g) If your lease is continued beyond its primary term, you must submit a report to the District Supervisor under paragraphs (h) and (i) of this section whenever production begins initially, whenever production ceases, whenever production resumes before the end of the 180-day period after having ceased, or whenever drilling or well-reworking operations begin before the end of the 180-day period.
(h) The reports required by paragraphs (a) and (g) of this section must contain:
(1) Name of lessee or operator;
(2) The well number, lease number, area, and block;
(3) As appropriate, the unit agreement name and number; and
(4) A description of the operation and pertinent dates.
(i) You must submit the reports required by paragraphs (a) and (g) of this section within the following timeframes:
(1) Initialization of production—within 5 days of initial production.
(2) Cessation of production—within 15 days after the first full month of zero production.
(3) Resumption of production—within 5 days of resuming production after ceasing production under paragraph (i)(2) of this section.
(4) Drilling or well reworking operations—within 5 days of beginning and completing the leaseholding operations.
(j) For leases continued beyond the primary term, you must immediately report to the District Supervisor if operations do not begin before the end of the 180-day period.
If the Secretary cancels your lease under this part or under 30 CFR part 256, you are entitled to compensation under § 250.184. Section 250.185 states conditions under which you will receive
(a) Continued activity on the lease would probably cause harm or damage to life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), or the marine, coastal, or human environment;
(b) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time;
(c) The advantages of cancellation outweigh the advantages of continuing the lease in force; and (d) A suspension has been in effect for at least 5 years or you request termination of the suspension and lease cancellation.
MMS may not approve an exploration plan (EP) under 30 CFR part 250, subpart B, if the Regional Supervisor determines that the proposed activities may cause serious harm or damage to life (including fish and other aquatic life), property, any mineral deposits, the national security or defense, or to the marine, coastal, or human environment, and that the proposed activity cannot be modified to avoid the condition(s). The Secretary may cancel the lease if:
(a) The primary lease term has not expired (or if the lease term has been extended) and exploration has been prohibited for 5 years following the disapproval; or
(b) You request cancellation at an earlier time.
(a) MMS may extend your lease if you submit a DPP and the Regional Supervisor disapproves the plan according to the regulations in 30 CFR part 250, subpart B. Following the disapproval:
(1) MMS will allow you to hold the lease for 5 years, or less time at your request;
(2) Any time within 5 years after the disapproval, you may reapply for approval of the same or a modified plan; and
(3) The Regional Supervisor will approve, disapprove, or require modification of the plan under 30 CFR part 250, subpart B.
(b) If the Regional Supervisor has not approved a DPP or required you to submit a DPP for approval or modification, the Secretary will cancel the lease:
(1) When the 5-year period in paragraph (a)(1) of this section expires; or
(2) If you request cancellation at an earlier time.
When the Secretary cancels a lease under §§ 250.181, 250.182 or 250.183 of this subpart, you are entitled to receive compensation under 43 U.S.C. 1334 (a)(2)(C). You must show the Director that the amount of compensation claimed is the lesser of paragraph (a) or (b) of this section:
(a) The fair value of the cancelled rights as of the date of cancellation, taking into account both:
(1) Anticipated revenues from the lease; and
(2) Costs reasonably anticipated on the lease, including:
(i) Costs of compliance with all applicable regulations and operating orders; and
(ii) Liability for cleanup costs or damages, or both, in the case of an oil spill.
(b) The excess, if any, over your revenues from the lease (plus interest thereon from the date of receipt to date of reimbursement) of:
(1) All consideration paid for the lease (plus interest from the date of payment to the date of reimbursement); and
(2) All your direct expenditures (plus interest from the date of payment to the date of reimbursement):
(i) After the issue date of the lease; and
(ii) For exploration or development, or both.
(c) Compensation for leases issued before September 18, 1978, will be equal to the amount specified in paragraph (a) of this section.
You will not receive compensation from MMS for lease cancellation if:
(a) MMS disapproves a DPP because you do not receive concurrence by the State under section 307(c)(3)(B) (i) or (ii) of the CZMA, and the Secretary of Commerce does not make the finding authorized by section 307(c)(3)(B)(iii) of the CZMA;
(b) You do not submit a DPP under 30 CFR part 250, subpart B or do not comply with the approved DPP;
(c) As the lessee of a nonproducing lease, you fail to comply with the Act, the lease, or the regulations issued under the Act, and the default continues for 30 days after MMS mails you a notice by overnight mail;
(d) The Regional Supervisor disapproves a DPP because you fail to comply with the requirements of applicable Federal law; or
(e) The Secretary forfeits and cancels a producing lease under section 5(d) of the Act (43 U.S.C. 1334(d)).
(a) You must submit information and reports as MMS requires.
(1) You may obtain copies of forms from, and submit completed forms to, the Regional or District Supervisor.
(2) Instead of paper copies of forms available from the Regional or District Supervisor, you may use your own computer-generated forms that are equal in size to MMS's forms. You must arrange the data on your form identical to the MMS form. If you generate your own form and it omits terms and conditions contained on the official MMS form, we will consider it to contain the omitted terms and conditions.
(3) You may submit digital data when the Region/District is equipped to accept it.
(b) When MMS specifies, you must include, for public information, an additional copy of such reports.
(1) You must mark it
(2) You must include all required information, except information exempt from public disclosure under § 250.196 or otherwise exempt from public disclosure under law or regulation.
(a) You must notify the District Supervisor of all serious accidents, any death or serious injury, and all fires, explosions, and blowouts connected with any activities or operations on the lease. You must report all spills of oil or other liquid pollutants according to 30 CFR part 254.
(b) If you hold an easement, right-of-way, or other permit, and your operation is related to the exercise of the easement, right-of-way, or other permit, you must comply with paragraph (a) by notifying and reporting to the Regional Supervisor any accidents occurring on the area covered by the easement, right-of-way, or other permit.
(c) Any investigation that the Secretary or the U.S. Coast Guard (USCG) conducts under the authority of sections 22(d)(1) and (2) of the Act (43 U.S.C. 1348 d(1) and (2)), is a fact-finding proceeding with no civil or criminal issues and no adverse parties. The purpose of the investigation is to prepare a public report that determines the cause or causes of the accident. The investigation may involve panel meetings conducted by a chairperson appointed by MMS. The following requirements must be met for any panel meetings involving persons giving testimony:
(1) A person giving testimony may have legal and/or other representative(s) present to provide advice or counsel while the person is giving testimony. The chairperson may require a verbatim transcript to be made of all oral testimony. The chairperson also may accept a sworn written statement in lieu of oral testimony.
(2) Only panel members, panel's legal advisors, and any experts the panel deems necessary may address questions to any person giving testimony.
(3) The chairperson may issue subpoenas to persons to appear and provide testimony and/or documents at a panel meeting. A subpoena may not require a person to attend a panel meeting held at a location more than 100 miles from where a subpoena is served.
(4) Any person giving testimony may request compensation for mileage and fees for service within 90 days after the panel meeting. The compensated expenses must be similar to mileage and fees the U.S. District Courts allow.
You must submit evacuation statistics to the Regional Supervisor for a natural occurrence such as an earthquake or hurricane. MMS will notify local and national authorities and the public, as appropriate. Statistics include facilities and rigs evacuated and amount of production shut-in for gas and oil. You must:
(a) Submit the statistics by fax or e-mail as soon as possible when evacuation occurs;
(b) Submit statistics on a daily basis by 11:00 a.m., as conditions allow, during the period of shut-in and evacuation;
(c) Inform MMS when you resume production; and
(d) Submit statistics either by MMS district or the total figures for your operations in the Region.
Any person may report to MMS an apparent violation or failure to comply with any provision of the Act, any provision of a lease, license, or permit issued under the Act, or any provision of any regulation or order issued under the Act. When MMS receives a report of an apparent violation, or when an MMS employee detects an apparent violation after making an initial determination of the validity, MMS will investigate according to MMS procedures.
(a) If it is likely that an archaeological resource exists in the lease area, the Regional Director will notify you in writing. You must include an archaeological report in the EP or DPP. If the archaeological report suggests that an archaeological resource may be present, you must either:
(1) Locate the site of any operation so as not to adversely affect the area where the archaeological resource may be; or
(2) Establish to the satisfaction of the Regional Director that an archaeological resource does not exist or will not be adversely affected by operations. This requires further archaeological investigation, conducted by an archaeologist and a geophysicist, using survey equipment and techniques the Regional Director considers appropriate. You must submit the investigation report to the Regional Director for review.
(b) If the Regional Director determines that an archaeological resource is likely to be present in the lease area and may be adversely affected by operations, the Regional Director will notify you immediately. You must not take any action that may adversely affect the archaeological resource until
(c) If you discover any archaeological resource while conducting operations in the lease area, you must immediately halt operations within the area of the discovery and report the discovery to the Regional Director. If investigations determine that the resource is significant, the Regional Director will tell you how to protect it.
(a) MMS will reimburse you for costs of reproducing data and information that the Regional Director requests if:
(1) You deliver geophysical and geological (G&G) data and information to MMS for the Regional Director to inspect or select and retain;
(2) MMS receives your request for reimbursement and the Regional Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate or at the lowest commercial rate established in the area, whichever is less.
(b) MMS will reimburse you for the costs of processing geophysical information (that does not include cost of data acquisition):
(1) If, at the request of the Regional Director, you processed the geophysical data or information in a form or manner other than that used in the normal conduct of business; or
(2) If you collected the information under a permit that MMS issued to you before October 1, 1985, and the Regional Director requests and retains the information.
(c) When you request reimbursement, you must identify reproduction and processing costs separately from acquisition costs.
(d) MMS will not reimburse you for data acquisition costs or for the costs of analyzing or processing geological information or interpreting geological or geophysical information.
MMS will protect data and information you submit under this part, as described in this section. The tables in paragraphs (a) and (b) of this section describe what data and information will be made available to the public without the consent of the lessee and under what circumstances and in what time period.
(a) MMS will disclose data and information you submit on MMS forms according to the following table:
(b) MMS will disclose lease data and information that you submit, but that are not usually submitted on MMS forms, according to the following table:
(a) MMS is incorporating by reference the documents listed in the table in paragraph (e) of this section. The Director of the Federal Register has approved this incorporation by reference according to 5 U.S.C. 552(a) and 1 CFR part 51.
(1) MMS will publish any changes to these documents in the
(2) MMS may make the rule amending the document effective without prior opportunity for public comment when MMS determines:
(i) That the revisions to a document result in safety improvements or represent new industry standard technology and do not impose undue costs on the affected parties; and
(ii) MMS meets the requirements for making a rule immediately effective under 5 U.S.C. 553.
(b) MMS incorporated each document or specific portion by reference in the sections noted. The entire document is incorporated by reference, unless the text of the corresponding sections in this part calls for compliance with specific portions of the listed documents. In each instance, the applicable document is the specific edition or specific edition and supplement or addendum cited in this section.
(c) Under §§ 250.141 and 250.142, you may comply with a later edition of a specific document incorporated by reference, provided:
(1) You show that complying with the later edition provides a degree of protection, safety, or performance equal to or better than would be achieved by compliance with the listed edition; and
(2) You obtain the prior written approval for alternative compliance from the authorized MMS official.
(d) You may inspect these documents at the Minerals Management Service, 381 Elden Street, Room 3313, Herndon, Virginia; or at the Office of the
(e) This paragraph lists documents incorporated by reference. To easily reference text of the corresponding sections with the list of documents incorporated by reference, the list is in alphanumerical order by organization and document.
(a) OMB has approved the information collection requirements in part 250 under 44 U.S.C. 3501
(b) Respondents are OCS oil, gas, and sulphur lessees and operators. The requirement to respond to the information collections in this part is mandated under the Act (43 U.S.C. 1331
(c) The Paperwork Reduction Act of 1995 requires us to inform the public that an agency may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collections of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
(e) MMS is collecting this information for the reasons given in the following table:
All exploration, development, and production activities except for preliminary activities shall be conducted in accordance with an Exploration Plan or a Development and Production Plan approved by the Regional Supervisor. A proposed plan may apply to one or more leases held by an individual lessee or may be submitted by a group of lessees. The Regional Supervisor may authorize lessees to jointly submit environmental information for leases that are in the same planning area and have similar environmental conditions. Any reference in this part to a Development and Production Plan shall be considered to include the Development Operations Coordination Document used in the western Gulf of Mexico (GOM) (see § 250.204(d)).
Preliminary activities are geological, geophysical, and other surveys necessary to develop a comprehensive Exploration Plan or Development and Production Plan. Such preliminary activities are those which do not result in any physical penetration of the seabed of greater than 500 feet and which do not result in any significant adverse impact on the natural resources of the Outer Continental Shelf (OCS). The Regional Supervisor may require prior notification of the type, scope, and timing of any survey.
(a) The Regional Supervisor is authorized to approve well location and spacing programs necessary for exploration and development of a leased sulphur deposit or fluid hydrocarbon reservoir giving consideration to, among other factors, the location of drilling units and platforms, extent and thickness of the sulphur deposit, geological and other reservoir characteristics, number of wells that can be economically drilled, protection of correlative rights, optimum recovery of resources, minimization of risk to the environment, and prevention of any unreasonable interference with other uses of the OCS. Well location and spacing programs shall be determined independently for each leased sulphur deposit or hydrocarbon-bearing reservoir in a manner that will locate wells in the optimum position for the most effective production of sulphur and/or reservoir fluids and avoid the drilling of unnecessary wells.
(b) For wells which could intersect or drain an offset property, the Regional Supervisor may require special measures to protect the rights of the lessor and objecting offset lessees.
(c) The lessee shall drill and produce the wells the Regional Supervisor determines are necessary to protect the lessor from loss by reason of production on other properties or in lieu thereof, with the approval of the Regional Supervisor, pay a sum determined by the Regional Supervisor as adequate to compensate the lessor for the lessee's failure to drill and produce any well. Payment of that sum shall be considered as the equivalent of production in paying quantities for the purpose of extending the lease term.
(a) The leasee shall submit for approval an Exploration Plan which includes the following:
(1) The proposed type and sequence of exploration activities to be undertaken together with a timetable for their performance from commencement to completion.
(2) A description of the type of mobile drilling unit, platform, or artificial island to be used including a discussion of the drilling program and important safety and pollution-prevention features. In the Alaska OCS Region, lessees shall include provisions for—
(i) Drilling a relief well should a blowout occur,
(ii) Loss or disablement of a drilling unit, and
(iii) Loss or damage to support craft.
(3) A table indicating the approximate location of each proposed exploratory well, including surface locations, proposed well depths, and water depth at well sites.
(b) The lessee shall submit the following supporting information to accompany the Exploration Plan:
(1) Data and information described below which the Regional Supervisor deems necessary to evaluate geologic conditions:
(i) Current structure contour maps drawn to the top of each prospective hydrocarbon accumulation showing the approximate surface and bottomhole location of each proposed well.
(ii) Full-scale interpreted, and if appropriate, migrated Common Depth Point seismic lines intersecting at or near the primary well locations.
(iii) A time versus depth chart based on the appropriate velocity analysis in the area of interpretation.
(iv) Interpreted structure sections corresponding to each seismic line submitted in paragraph (b)(1)(ii) of this section showing the location and proposed depth of each well.
(v) A generalized stratigraphic column from the surface to total depth.
(vi) A description of the geology of the prospect.
(vii) A plat showing exploration seismic coverage of the lease.
(viii) A bathymetry map showing surface locations of proposed wells.
(ix) An analysis of seafloor and subsurface geologic and manmade hazards. Unless the lessee can demonstrate to the satisfaction of the Regional Supervisor that data sufficient to determine the presence or absence of such conditions are available, the lessee shall conduct a shallow hazards survey in accordance with the Regional Supervisor's specifications. The Regional Supervisor may require the submission of a shallow hazards report and the data upon which the analysis is based.
(2) An oil-spill response plan as described in part 254 or reference to an approved Regional Response Plan.
(3) A discussion of the measures that have been or will be taken to satisfy the conditions of lease stipulations.
(4) A list of the proposed drilling fluids, including components and their chemical compositions, information on the projected amounts and rates of drilling fluid and cuttings discharges, and method of disposal.
(5) Information concerning the presence of hydrogen sulfide (H
(i) A classification of the lease area as to whether it is within an area known to contain H
(ii) If the classification is an area known to contain H
(6) A detailed discussion of new or unusual technology to be employed. The lessee shall indicate which portions of the supporting information the lessee believes are exempt from disclosure under the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the implementing regulations (43 CFR part 2). The lessee shall include a written discussion of the general subject matter of the deleted portions for transmittal to the recipients of plan copies.
(7) A brief description of the onshore facilities to be used to support the exploration activities including information as to whether the facilities are existing, proposed, or are to be expanded; a brief description of support vessels to be used and information concerning their frequency of travel; and a map showing the lease relative to the shoreline and depicting proposed transportation routes.
(8) For onshore support facilities, except in the western GOM, indicate the following:
(i) The location, size, number, and land requirements (including rights-of-way and easements) of the onshore support and storage facilities and, where possible, a timetable for the acquisition of lands and the construction or expansion of any facilities.
(ii) The estimated number of persons expected to be employed in support of offshore, onshore, and transportation activities and, where possible, the approximate number of new employees
(iii) Major supplies, services, energy, water, or other resources within affected States necessary for carrying out the related plan.
(iv) The source, composition, frequency, and duration of emissions of air pollutants.
(9) The quantity, composition, and method of disposal of solid and liquid wastes and pollutants likely to be generated by offshore, onshore, and transportation operations.
(10) Historic weather patterns and other meteorological conditions of offshore areas including temperature, sky cover and visibility, precipitation, storm frequency and magnitude, wind direction and velocity, and freezing and icing conditions listing, where possible, the means and extremes of each.
(11) Physical oceanography including onsite direction and velocity of currents and tides, sea states, temperature, and salinity, water quality, and icing conditions, where appropriate.
(12) Onsite flora and fauna including both pelagic and benthic communities, transitory birds and mammals that may breed or migrate through the area when proposed activities are being conducted, identification of endangered and threatened species and their critical habitats that could be affected by proposed activities, and typical fishing seasons and locations of fishing activities. The results of any biological surveys required by the Regional Supervisor (including a copy of survey reports or references to previously submitted reports) should be incorporated into this discussion.
(13) Environmentally sensitive areas (onshore as well as offshore), e.g., refuges, preserves, sanctuaries, rookeries, calving grounds, and areas of particular concern identified by an affected State pursuant to the Coastal Zone Management Act (CZMA) which may be affected by the proposed activities.
(14) Onsite uses of the area based on information available, e.g., shipping, military use, recreation, boating, commercial fishing, subsistence hunting and fishing, and other mineral exploration in the area.
(15) If the Regional Director believes that an archaeological resource may exist in the lease area, the Regional Director will notify the lessee in writing. Prior to commencing any operations, the lessee shall prepare a report, as specified by the Regional Director, to determine the potential existence of any archaeological resource that may be affected by operations. The report shall be prepared by an archaeologist and geophysicist and shall be based on an assessment of data from remote-sensing surveys and of other pertinent archaeological and environmental information.
(16) Existing and planned monitoring systems that are measuring or will measure environmental conditions and provide data and information on the impacts of activities in the geographic areas.
(17) An assessment of the direct and cumulative effects on the offshore and onshore environments expected to occur as a result of implementation of the Exploration Plan, expressed in terms of magnitude and duration, with special emphasis upon the identification and evaluation of unavoidable and irreversible impacts on the environment. Measures to minimize or mitigate impacts should be identified and discussed.
(18) Certificate(s) of coastal zone consistency as provided in 15 CFR part 930.
(19) For each OCS facility, the lessee shall submit the information described below when it is needed to make the findings under § 250.303 or § 250.304 of this part:
(i)(A) Projected emissions from each proposed or modified facility for each year of operation and the basis for all calculations to include (if the drilling unit has not yet been determined, the lessee shall use worst-case estimates for the type of unit proposed):
(
(
(
(
(
(B) The distance of each proposed facility from the mean high water mark (mean higher high water mark on the Pacific coast) of any State.
(ii)(A) The model(s) used to determine the effect on the onshore air quality of emissions from each facility, or from other facilities when required by the Regional Supervisor, and the results obtained through the use of the model(s). Only model(s) that has been approved by the Director may be used.
(B) The best available meteorological information and data consistent with the model(s) used stating the basis for the data and information selected.
(iii) The air quality status of any onshore area where the air quality is significantly affected (within the meaning of § 250.303 of this part) by projected emissions from each facility proposed in the plan. The area should be classified as nonattainment, attainment, or unclassifiable to include the status of each area by air pollutant, the class of attainment area, and the air-pollution control agency whose jurisdiction covers the area identified.
(iv) The emission-reduction controls available to reduce emissions, including the source, the emission-reduction control technology, reductions to be achieved, and monitoring system the lessee proposes to use to measure emissions. The lessee shall indicate which emission-reduction control technology the lessee believes constitutes the best available control technology and the basis for that opinion.
(20) The name, address, and telephone number of an individual employee of the lessee to whom inquiries by the Regional Supervisor and the affected State(s) may be made.
(21) Such other information and data as the Regional Supervisor may require.
(c) Information and data discussed in other documents previously submitted to MMS or otherwise readily available to reviewers may be referenced. The material being referenced shall be cited, described briefly, and include a statement of where the material is available for inspection. Any material based on proprietary data which is not itself available for inspection shall not be so referenced.
(d) The Regional Director, after consultation with the Governor of the affected State(s) or the Governor's designated representative, the CZM agency of affected State(s), and the Office of Ocean and Coastal Resource Management of the National Oceanic and Atmospheric Administration (NOAA) may limit the amount of information required to be included to that necessary to assure conformance with the Act, other laws, applicable regulations, and lease provisions.
(e) The Regional Supervisor shall determine within 10 working days after receipt of the Exploration Plan whether additional information is needed. If no deficiencies are identified and the required number of copies have been received, the plan will be deemed submitted.
(f) Within 2 working days after we deem the Exploration Plan submitted, the Regional Supervisor will send by receipted mail a copy of the plan (except those portions exempt from disclosure under the Freedom of Information Act and 43 CFR part 2) to the Governor or the Governor's designated representative and the CZM agency of each affected State. Consistency review begins when the State's CZM agency receives a copy of the deemed submitted plan, consistency certification, and required necessary data and information as directed by 15 CFR 930.78.
(g) In accordance with the National Environmental Policy Act (NEPA), the Regional Supervisor shall evaluate the environmental impacts of the activities described in the Exploration Plan.
(h) In the evaluation of an Exploration Plan, the Regional Supervisor shall consider written comments from
(i) Within 30 days of submission of a proposed Exploration Plan, the Regional Supervisor shall accomplish one of the following:
(1) Approve the plan;
(2) Require the lessee to modify any plan which is inconsistent with the provisions of the lease, the Act, or the regulations prescribed under the Act including air quality, environmental, safety, and health requirements; or
(3) Disapprove the plan if the Regional Supervisor determines that a proposed activity would probably cause serious harm or damage to life (including fish and other aquatic life), property, natural resources offshore including any mineral deposits (in areas leased or not leased), the national security or defense, or the marine, coastal, or human environment, and that the proposed activity cannot be modified to avoid the condition(s).
(j) The Regional Supervisor shall notify the lessee in writing of the reason(s) for disapproving an Exploration Plan or for requiring modification of a plan. For plans requiring modification, the Regional Supervisor shall also notify the lessee in writing of the conditions that must be met for plan approval.
(k)(1) The lessee may resubmit an Exploration Plan, as modified, to the Regional Supervisor in the same manner as for a new plan. Only information related to the proposed modifications need be submitted. The Regional Supervisor shall approve, disapprove, or require modification of the resubmitted plan based upon the criteria in paragraph (i) of this section within 30 days of the resubmission date.
(2) An Exploration Plan which has been disapproved pursuant to paragraph (i)(3) of this section may be resubmitted if there is a change in the conditions which caused it to be disapproved. The Regional Supervisor shall approve, require modification, or disapprove such a plan within 30 days of the resubmission date.
(l) When a State objects to a lessee's coastal zone consistency certification, the lessee shall modify the plan to accommodate the State's objection(s) and resubmit the plan to—
(1) The Regional Supervisor for review pursuant to the criteria in paragraphs (h), (i), and (j) of this section; and
(2) Through the Regional Supervisor to the State for review pursuant to the CZMA and the implementing regulations (15 CFR 930.83 and 930.84).
(m) If the Regional Supervisor disapproves an Exploration Plan, the Secretary may, subject to the provisions of section 5(a)(2)(B) of the Act and the implementing regulations in § 250.182 and 256.77 of this chapter II, cancel the lease(s), and the lessee shall be entitled to compensation in accordance with section 5(a)(2)(c) of the Act.
(n)(1) The Regional Supervisor shall periodically review the activities being conducted under an approved Exploration Plan and may request updated information on schedules and procedures. The frequency and extent of the Regional Supervisor's review shall be based upon the significance of any changes in available information and in other onshore or offshore conditions affecting or affected by exploration activities being conducted pursuant to the plan. If the review indicates that the plan should be revised to meet the requirements of this part, the Regional Supervisor shall require the needed revision.
(2) Revisions to an approved or pending Exploration Plan, whether initiated by the lessee or ordered by the Regional Supervisor, shall be submitted to the Regional Supervisor for approval. Only information related to the proposed revisions need be submitted.
(o) To ensure safety and protection of the environment and archaeological resources, the Regional Director may authorize or direct the lessee to conduct geological, geophysical, biological, archaeological, or other surveys or monitoring programs. The lessee shall provide the Regional Director, upon request, with copies of any data obtained as a result of those surveys and monitoring programs.
(p) The lessee may not drill any well until the District Supervisor's approval of an Application for Permit to Drill (APD), submitted in accordance with the requirements of § 250.414 of this part, has been received. The District Supervisor shall not approve any APD until all affected States with approved CZM programs have concurred or have been conclusively presumed to concur with the applicant's coastal zone consistency certification accompanying a plan, or the Secretary of Commerce has made the finding authorized by section 307(c)(3)(B)(iii) of the CZMA. The APD's must conform to the activities described in detail in the approved Exploration Plan and shall not be subject to a separate State coastal zone consistency review.
(q) Nothing in this section or in an approved plan shall limit the lessee's responsibility to take appropriate measures to meet emergency situations. In such situations, the Regional Supervisor may approve or require departures from an approved Exploration Plan.
(a) The lessee shall submit for approval a Development and Production Plan which includes the following:
(1) A description of and schedule for the development and production activities to be performed including plan commencement date, date of first production, total time to complete all development and production activities, and dates and sequences for drilling wells and installing facilities and equipment.
(2) A description of any drilling vessels, platforms, pipelines, or other facilities and operations located offshore which are proposed or known by the lessee (whether or not owned or operated by the lessee) to be directly related to the proposed development, including the location, size, design, and important safety, pollution prevention, and environmental monitoring features of the facilities and operations.
(b) The lessee shall submit the following supporting information to accompany the Development and Production Plan:
(1) Geological and geophysical (G&G) data and information, including the following:
(i) A plat showing the surface location of any proposed fixed structure or well.
(ii) A plat showing the surface and bottomhole locations and giving the measured and true vertical depths for each proposed well.
(iii) Current interpretations of relevant G&G data.
(iv) Current structure map(s) showing the surface and bottomhole location of each proposed well and the depths of expected productive formations.
(v) Interpreted structure sections showing the depths of expected productive formations.
(vi) A bathymetric map showing surface locations of fixed structures and wells or a table of water depths at each proposed site.
(vii) A discussion of seafloor conditions including a shallow hazards analysis for proposed drilling and platform sites and pipeline routes. This information shall be derived from the shallow hazards report required by § 250.909 of this part.
(2) Information concerning the presence of H
(i) A classification of the lease area as to whether it is within an area known to contain H
(ii) If the classification is an area known to contain H
(3) A description of the environmental safeguards to be implemented, including an updated oil-spill response plan as described in part 254 of this chapter or reference to an approved plan.
(4) A discussion of the steps that have been or will be taken to satisfy the conditions of lease stipulations.
(5)(i) A description of technology and reservoir engineering practices intended to increase the ultimate recovery of oil and gas, i.e., secondary, tertiary, or other enhanced recovery practices;
(ii) A description of technology and recovery practices and procedures intended to assure optimum recovery of sulphur; or
(iii) A description of technology and recovery practices and procedures intended to assure optimum recovery of oil and gas and sulphur.
(6) A discussion of the proposed drilling and completion programs.
(7) A detailed description of new or unusual technology to be employed. The lessee shall indicate which portions of the information the lessee believes are exempt from disclosure under the FOIA (5 U.S.C. 552) and the implementing regulations (43 CFR part 2). The lessee shall include a written discussion of the general subject matter of the deleted portions for transmittal to recipients of plan copies.
(8) A brief description of the following:
(i) The location, description, and size of any offshore, and to the maximum extent practicable, land-based operations to be conducted or contracted for as a result of the proposed activity, including the following:
(A) The acreage required within a State for facilities, rights-of-way, and easements.
(B) The means proposed for transportation of oil, gas, and sulphur to shore; the routes to be followed by each mode of transportation; and the estimated quantities of oil, gas, and sulphur to be moved along such routes.
(C) An estimate of the frequency of boat and aircraft departures and arrivals, the onshore location of terminals, and the normal routes for each mode of transportation.
(ii) A list of the proposed drilling fluids including components and their chemical compositions, information on the projected amounts and rates of drilling fluid and cuttings discharges, and method of disposal. If the information is provided in an approved Environmental Protection Agency, National Pollutant Discharge Elimination System permit, or a pending permit application, the lessee may reference these documents.
(iii) The quantities, types, and plans for disposal of other solid and liquid wastes and pollutants likely to be generated by offshore, onshore, and transport operations and, regarding any wastes which may require onshore disposal, the means of transportation to be used to bring the wastes to shore, disposal methods to be utilized, and location of onshore waste disposal or treatment facilities.
(iv) The following information on onshore support facilities, except in the western GOM:
(A) The approximate number, timing, and duration of employment of persons who will be engaged in onshore development and production activities, an approximate number of local personnel who will be employed for or in support of the development activities (classified by the major skills or crafts that will be required from local sources and estimated number of each such skill needed), and the approximate total number of persons who will be employed during the onshore construction activity and during all activities related to offshore development and production.
(B) The approximate number of people and families to be added to the population of local nearshore areas as a result of the planned development.
(C) An estimate of significant quantities of energy and resources to be used or consumed including electricity, water, oil and gas, diesel fuel, aggregate, or other supplies which may be purchased within an affected State.
(D) The types of contractors or vendors which will be needed, although not specifically identified, and which may place a demand on local goods and services.
(E) The source, composition, frequency, and duration of emissions of air pollutants.
(v) A narrative description of the existing environment with an emphasis placed on those environmental values that may be affected by the proposed action. This section shall contain a description of the physical environment of the area covered by the related plan. This portion of the plan shall include data and information obtained or developed by the lessee together with other pertinent information and data available to the lessee from other sources. The environmental information and data shall include the following, where appropriate:
(A) If the Regional Director believes that an archaeological resource may exist in the lease area, the Regional Director will notify the lessee in writing. Prior to commencing any operations, the lessee shall prepare a report, as specified by the Regional Director, to determine the potential existence of any archaeological resource that may be affected by operations. The report shall be prepared by an archaeologist and geophysicist and shall be based on an assessment of data from remote-sensing surveys and of other pertinent archaeological and environmental information.
(B) The aquatic biota, including a description of fishery and marine mammal use of the lease and the significance of the lease, and a description of any threatened and endangered species and their critical habitat. The results of any biological surveys required by the Regional Supervisor (including a copy of survey reports or references to previously submitted reports) should be incorporated into these discussions.
(C) Environmentally sensitive areas (e.g., refuges, preserves, sanctuaries, rookeries, calving grounds, coastal habitat, beaches, and areas of particular environmental concern) which may be affected by the proposed activities.
(D) The predevelopment, ambient water-column quality and temperature data for incremental depths for the areas encompassed by the plan.
(E) The physical oceanography, including ocean currents described as to prevailing direction, seasonal variations, and variations at different water depths in the lease.
(F) Historic weather patterns and other meteorological conditions, including storm frequency and magnitude, wave height and direction, wind direction and velocity, air temperature, visibility, freezing and icing conditions, and ambient air quality listing, where possible, the means and extremes of each.
(G) The other uses of the area known to the lessee, including military use for national security or defense, subsistence hunting and fishing, commercial fishing, recreation, shipping, and other mineral exploration or development.
(H) The existing or planned monitoring systems that are measuring or will measure impacts of activities on the environment in the planning area.
(9) For sulphur operations, the degree of subsidence that is expected at various stages of production, and measures that will be taken to assure safety of operations and protection of the environment. Special attention shall be given to the effects of subsidence on existing or potential oil and gas production, fixed bottom-founded structures, and pipelines.
(10) For sulphur operations, a discussion of the potential toxic or thermal effects on the environment caused by the discharge of bleedwater, including a description of the measures that will be taken into account to mitigate these impacts.
(11) An assessment of the effects on the environment expected to occur as a result of implementation of the plan, identifying specific and cumulative impacts that may occur both onshore and
(12) A discussion of alternatives to the activities proposed that were considered during the development of the plan including a comparison of the environmental effects.
(13) Certificate(s) of coastal zone consistency as provided in 15 CFR part 930.
(14) For each OCS facility, such information described below needed to make the findings under § 250.303 or § 250.304 of this part:
(i)(A) Projected emissions from each proposed or modified facility for each year of operation and basis for all calculations to include the following:
(
(
(
(
(
(B) The distance of each proposed facility from the mean high water mark (mean higher high water mark on the Pacific coast) of any State.
(ii)(A) The model(s) used to determine the effect on the onshore air quality of emissions from each facility, or from other facilities when required by the Regional Supervisor, and the result obtained through the use of the model(s). Only model(s) that has been approved by the Director may be used.
(B) The best available meteorological information and data consistent with the model(s) used stating the basis for the information and data selected.
(iii) The air quality status of any onshore area where the air quality is significantly affected (within the meaning of § 250.303 of this part) by projected emissions from each facility proposed in the plan. The area should be classified as nonattainment, attainment, or unclassifiable listing the status of each area by air pollutant, the class of attainment areas, and the air pollution control agency whose jurisdiction covers the area identified.
(iv)(A) The emission-reduction controls available to reduce emissions including the source, emission-reduction control technology, reductions to be achieved, and monitoring system the lessee proposes to use to measure emissions. The lessee shall indicate which emission-reduction control technology the lessee believes constitutes the best available control technology and the basis for that opinion.
(B) The ownership of the offshore and onshore offsetting source(s) and the reduction obtainable from each offsetting source.
(15) A brief discussion of any approved or anticipated suspensions of production necessary to hold the lease(s) in an active status.
(16) The name, address, and telephone number of an individual employee of the lessee to whom inquiries by the Regional Supervisor and the affected State(s) may be directed.
(17) Such other data and information as the Regional Supervisor may require.
(c) Data and information discussed in other documents previously submitted to MMS or otherwise readily available to reviewers may be incorporated by reference. The material being incorporated shall be cited and described briefly and include a statement of where the material is available for inspection. Any material based on proprietary data which is not itself available for inspection shall not be incorporated by reference.
(d)(1) Development and Production Plans are not required for leases in the western GOM. For these leases, the lessee shall submit to the Regional Supervisor for approval a Development Operations Coordination Document with all information necessary to assure conformance with the Act, other laws, applicable regulations, lease provisions, or as otherwise needed to carry out the functions and responsibilities of the Regional Supervisor.
(2) Any information required in paragraph (d)(1) of this section shall be considered a Development and Production Plan for the purpose of references in any law, regulation, lease provision, agreement, or other document referring to the preparation or submission of a plan.
(e) The Regional Director, after consultation with the Governor(s) of the affected State(s) or the Governor's designated representative, the CZM agency of the affected State(s), and the Office of Ocean and Coastal Resource Management of NOAA may limit the amount of information required to be included in a Development and Production Plan to that necessary to assure conformance with the Act, other laws, applicable regulations, and lease provisions. In determining the information to be included in a plan, the Regional Director shall consider current and expected operating conditions together with experience gained during past operations of a similar nature in the area of proposed activities.
(f) The Regional Supervisor shall determine within 20 working days after receipt whether additional material is needed. If no deficiencies are identified and the requested number of copies have been received, the plan shall be deemed submitted.
(g) Within 5 working days after a Development and Production Plan has been deemed submitted, the Regional Supervisor shall transmit a copy of the plan, except for those portions of the plan determined to be exempt from disclosure under the FOIA and the implementing regulations (43 CFR part 2), to the Governor or the Governor's designated representative and the CZM agency of each affected State and to the executive of each affected local government that requests a copy. The Regional Supervisor shall make copies available to appropriate Federal Agencies, interstate entities, and the public. The plan will be available for review at the appropriate MMS Regional Public Information Office.
(h) The Governor or the Governor's designated representative and the CZM agency of each affected State and the executive of each affected local government shall have 60 days from the date of receipt of the Development and Production Plan to submit comments and recommendations to the Regional Supervisor. The executive of any affected local government must forward all recommendations to the Governor of the State prior to submitting them to the Regional Supervisor. The Regional Supervisor shall accept those recommendations from the Governor that provide for a reasonable balance between the national interest and the well-being of the citizens of the affected State. The Regional Supervisor shall explain in writing the reasons for accepting or rejecting any recommendations. In addition, any interested Federal Agency or person may submit comments and recommendations to the Regional Supervisor. All comments and recommendations shall be made available to the public.
(i) We will process the plan according to this section and 15 CFR part 930. Accordingly, consistency review begins when the State's CZM agency receives a copy of the deemed submitted plan, consistency certification, and required necessary data and information as directed by 15 CFR 930.78.
(j) The Regional Supervisor will evaluate the environmental impact of the activities described in the Development and Production Plan (DPP) and prepare the appropriate environmental documentation required by the National Environmental Policy Act of 1969. At least once in each planning area (other than the western and central Gulf of Mexico planning areas), we will prepare an environmental impact statement (EIS) and send copies of the draft EIS to the Governor of each affected State and the executive of each affected local government that requests a copy. Additionally, when we prepare a DPP EIS and when the State's federally approved coastal
(k) Prior to or immediately after a determination by the Director that approval of a Development and Production Plan requires that the procedures under NEPA shall commence, the Regional Supervisor may require lessees of tracts in the vicinity, for which Development and Production Plans have not been approved, to submit preliminary or final plans for their leases.
(l) No later than 60 days after the last day of the comment period provided in paragraph (h) of this section or within 60 days of the release of the final EIS describing the proposed activities, the Regional Supervisor shall accomplish the following:
(1) Approve the plan;
(2) Require modification of the plan if it is determined that the lessee has failed to make adequate provisions for safety, environmental protection, or conservation of resources including compliance with the regulations prescribed under the Act; or
(3) Disapprove the plan if one or more of the following occurs:
(i) The lessee fails to demonstrate that compliance with the requirements of the Act, provisions of the regulations prescribed under the Act, or other applicable Federal laws is possible;
(ii) State concurrence with the applicant's coastal zone consistency certification has not been received, the State's concurrence has not been conclusively presumed, or the State objects to the consistency certification, and the Secretary of Commerce does not make the determination authorized by section 307(c)(3)(B)(iii) of the CZMA;
(iii) Operations threaten national security or defense; or
(iv) Exceptional geological conditions in the lease area, exceptional resource value in the marine or coastal environment, or other exceptional circumstances exist, and all of the following:
(A) Implementation of the plan would probably cause serious harm or damage to life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), the national security or defense, or to the marine, coastal, or human environments.
(B) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time.
(C) The advantages of disapproving the plan outweigh the advantages of development and production.
(m) The Regional Supervisor shall notify the lessee in writing of the reason(s) for disapproving a Development and Production Plan or for requiring modification of a plan and the conditions which must be met for plan approval.
(n) The lessee may resubmit a Development and Production Plan, as modified, to the Regional Supervisor. Only information related to the proposed modifications need be submitted. Within 60 days following the 60-day comment period provided for in paragraph (h) of this section, the Regional Supervisor shall approve, disapprove, or require modification of the modified plan.
(o)(1) If a Development and Production Plan is disapproved for the sole reason that a State consistency certification has not been obtained, the Regional Supervisor shall approve the plan upon receipt of the concurrence, at the time when concurrence is conclusively presumed, or when the Secretary of Commerce makes a finding authorized by section 307(c)(3)(B)(iii) of the CZMA.
(2) If a Development and Production Plan is disapproved because a State objects to the lessee's coastal zone consistency certification, the lessee shall modify the plan to accommodate the State's objection(s) and resubmit the plan to (i) the Regional Supervisor for review pursuant to the criteria in paragraph (l) of this section; and (ii) through the Regional Supervisor, to the State for review pursuant to the CZMA and the implementing regulations (15 CFR 930.83 and 930.84). Alternatively, the lessee may appeal the State's objection to the Secretary of
(p) Development and Production Plans disapproved pursuant to paragraph (l)(3) of this section are subject to the provisions of section 25(h)(2) of the Act and the implementing regulations in §§ 250.183 and 256.77 of this chapter.
(q)(1) The Regional Supervisor shall periodically review the activities being conducted under an approved Development and Production Plan. The frequency and extent of the Regional Supervisor's review shall be based upon the significance of any changes in available information and onshore or offshore conditions affecting or impacted by development or production activities being conducted pursuant to the plan. If the review indicates that the plan should be revised to meet the requirements of this part, the Regional Supervisor shall require the needed revisions.
(2) Revisions to an approved or pending Development and Production Plan, whether initiated by the lessee or ordered by the Regional Supervisor, shall be submitted to the Regional Supervisor for approval. Only information related to the proposed revisions need be submitted. When the Regional Supervisor determines that a proposed revision could result in a significant change in the impacts previously identified and evaluated, requires additional permits, or proposes activities not previously identified and evaluated, the revision shall be subject to all of the procedures in this section.
(3) When any revision to an approved Development and Production Plan is proposed by the lessee, the Regional Supervisor may approve the revision if it is determined that the revision is consistent with the protection of the marine, coastal, and human environments and will lead to greater recovery of oil and natural gas; will improve the efficiency, safety, and environmental protection of the recovery operation; is the only means available to avoid substantial economic hardship to the lessee; or is otherwise not inconsistent with the provisions of the Act.
(r) Whenever the lessee fails to submit a Development and Production Plan in accordance with provisions of this section or fails to comply with an approved plan, the lease may be cancelled in accordance with sections 5 (c) and (d) of the Act and the implementing regulations in §§ 250.183 and 256.77 of this chapter.
(s) To ensure safety and protection of the environment and archaeological resources, the Regional Director may authorize or direct the lessee to conduct geological, geophysical, biological, archaeological, or other surveys or monitoring programs. The lessee shall provide the Regional Director, upon request, copies of any data obtained as a result of those surveys and monitoring programs.
(t) The lessee may not drill any well until the District Supervisor's approval of an APD, filed in accordance with the requirements of § 250.414 of this part, has been received. All APD's and applications to install platforms and structures, pipelines, and production equipment must conform to the activities described in detail in the approved Development and Production Plan and shall not be subject to a separate State coastal zone consistency review.
(u) Nothing in this section or approved plans shall limit the lessee's responsibility to take appropriate measures to meet emergency situations. In such situations, the Regional Supervisor may approve or require departures from an approved Development and Production Plan.
(a) During the exploration, development, production, and transportation
(1) When pollution occurs as a result of operations conducted by or on behalf of the lessee and the pollution damages or threatens to damage life (including fish and other aquatic life), property, any mineral deposits (in areas leased or not leased), or the marine, coastal, or human environment, the control and removal of the pollution to the satisfaction of the District Supervisor shall be at the expense of the lessee. Immediate corrective action shall be taken in all cases where pollution has occurred. Corrective action shall be subject to modification when directed by the District Supervisor.
(2) If the lessee fails to control and remove the pollution, the Director, in cooperation with other appropriate Agencies of Federal, State, and local governments, or in cooperation with the lessee, or both, shall have the right to control and remove the pollution at the lessee's expense. Such action shall not relieve the lessee of any responsibility provided for by law.
(b)(1) The District Supervisor may restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. The District Supervisor may also restrict the use of components which could cause unreasonable degradation to the marine environment. No petroleum-based substances, including diesel fuel, may be added to the drilling mud system without prior approval of the District Supervisor.
(2) Approval of the method of disposal of drill cuttings, sand, and other well solids shall be obtained from the District Supervisor.
(3) All hydrocarbon-handling equipment for testing and production such as separators, tanks, and treaters shall be designed, installed, and operated to prevent pollution. Maintenance or repairs which are necessary to prevent pollution of offshore waters shall be undertaken immediately.
(4) Curbs, gutters, drip pans, and drains shall be installed in deck areas in a manner necessary to collect all contaminants not authorized for discharge. Oil drainage shall be piped to a properly designed, operated, and maintained sump system which will automatically maintain the oil at a level sufficient to prevent discharge of oil into offshore waters. All gravity drains shall be equipped with a water trap or other means to prevent gas in the sump system from escaping through the drains. Sump piles shall not be used as processing devices to treat or skim liquids but may be used to collect treated-produced water, treated-produced sand, or liquids from drip pans and deck drains and as a final trap for hydrocarbon liquids in the event of equipment upsets. Improperly designed, operated, or maintained sump piles which do not prevent the discharge of oil into offshore waters shall be replaced or repaired.
(5) On artificial islands, all vessels containing hydrocarbons shall be placed inside an impervious berm or otherwise protected to contain spills. Drainage shall be directed away from the drilling rig to a sump. Drains and sumps shall be constructed to prevent seepage.
(6) Disposal of equipment, cables, chains, containers, or other materials into offshore waters is prohibited.
(c) Materials, equipment, tools, containers, and other items used in the Outer Continental Shelf (OCS) which are of such shape or configuration that they are likely to snag or damage fishing devices shall be handled and marked as follows:
(1) All loose material, small tools, and other small objects shall be kept in a suitable storage area or a marked container when not in use and in a marked container before transport over offshore waters;
(2) All cable, chain, or wire segments shall be recovered after use and securely stored until suitable disposal is accomplished;
(3) Skid-mounted equipment, portable containers, spools or reels, and drums shall be marked with the owner's name prior to use or transport over offshore waters; and
(4) All markings must clearly identify the owner and must be durable enough to resist the effects of the environmental conditions to which they may be exposed.
(d) Any of the items described in paragraph (c) of this section that are lost overboard shall be recorded on the facility's daily operations report, as appropriate, and reported to the District Supervisor.
(a) Drilling and production facilities shall be inspected daily or at intervals approved or prescribed by the District Supervisor to determine if pollution is occurring. Necessary maintenance or repairs shall be made immediately. Records of such inspections and repairs shall be maintained at the facility or at a nearby manned facility for 2 years.
For purposes of §§ 250.303 and 250.304 of this part:
(a)
(b)
(2) For a facility identified by the Regional Supervisor in paragraph (b)(1) of this section, the Regional Supervisor shall require the lessee to refer to the information required in § 250.203(b)(19) or § 250.204(b)(12) of this part and to submit only that information required to make the necessary findings under paragraphs (d) through (i) of this section. The lessee shall submit this information within 120 days of the Regional Supervisor's determination or within a longer period of time at the discretion of the Regional Supervisor. The lessee shall comply with the requirements of this section as necessary.
(c)
(d)
(e)
(f)
(2) The projected emissions of VOC from any facility which is not exempt under paragraph (d) of this section for
(g)
(2) The projected emissions of any air pollutant other than VOC from any facility which significantly affect the air quality of an attainment or unclassifiable area shall be reduced through the application of BACT.
(i) Except for temporary facilities, the lessee also shall use an approved air quality model to determine whether the emissions of TSP or SO
(ii) If the maximum allowable increases are exceeded, the lessee shall apply whatever additional emission controls are necessary to reduce or offset the remaining emissions of TSP or SO
(3)(i) The projected emissions of VOC from any facility, except a temporary facility, which significantly affect the onshore air quality of a nonattainment area shall be fully reduced. This shall be done through the application of BACT and, if additional reductions are necessary, through the application of additional emission controls or through the acquisition of offshore or onshore offsets.
(ii) The projected emissions of VOC from any facility which significantly affect the onshore air quality of an attainment area shall be reduced through the application of BACT.
(4)(i) If projected emissions from a facility significantly affect the onshore air quality of both a nonattainment and an attainment or unclassifiable area, the regulatory requirements applicable to projected emissions significantly affecting a nonattainment area shall apply.
(ii) If projected emissions from a facility significantly affect the onshore air quality of more than one class of attainment area, the lessee must reduce projected emissions to meet the maximum allowable increases specified for each class in paragraph (g)(2)(i) of this section.
(h)
(i)
(j)
(k)
(l)
(a)
(2) The Regional Supervisor may require lessees of existing facilities to submit basic emission data to a State submitting a request under paragraph (a)(1) of this section.
(3) The State submitting a request under paragraph (a)(1) of this section may submit information from its emission inventory which indicates that emissions from existing facilities may be significantly affecting the air quality of the onshore area of the State. The lessee shall be given the opportunity to present information to the Regional Supervisor which demonstrates that the facility is not significantly affecting the air quality of the State.
(4) The Regional Supervisor shall evaluate the information submitted under paragraph (a)(3) of this section and shall determine, based on the basic emission data, available meteorological data, and the distance of the facility or facilities from the onshore area, whether any existing facility has the potential to significantly affect the air quality of the onshore area of the State.
(5) If the Regional Supervisor determines that no existing facility has the potential to significantly affect the air quality of the onshore area of the State submitting information under paragraph (a)(3) of this section, the Regional Supervisor shall notify the State of and explain the reasons for this finding.
(6) If the Regional Supervisor determines that an existing facility has the potential to significantly affect the air quality of an onshore area of the State submitting information under paragraph (a)(3) of this section, the Regional Supervisor shall require the lessee to refer to the information requirements under § 250.203(b)(19) or 250.204(b)(12) of this part and submit only that information required to make the necessary findings under paragraphs (b) through (e) of this section. The lessee shall submit this information within 120 days of the Regional Supervisor's determination or within a
(b)
(c)
(d)
(2) The projected emissions of VOC from any facility which is not exempt under paragraph (b) of this section for that air pollutant shall be deemed to significantly affect the air quality of the onshore area for VOC.
(e)
(2) The lessee shall submit a compliance schedule for the application of BACT. If it is necessary to cease operations to allow for the installation of emission controls, the lessee may apply for a suspension of operations under the provisions of § 250.174 of this part.
(f)
(g)
(h)
The lessee shall take necessary precautions to keep its wells under control at all times. The lessee shall utilize the best available and safest drilling technology in order to enhance the evaluation of conditions of abnormal pressure and to minimize the potential for the well to flow or kick. The lessee shall utilize personnel who are trained and competent and shall utilize and maintain equipment and materials necessary to assure the safety and protection of personnel, equipment, natural resources, and the environment.
(a)
(2) Prior to commencing operation, drilling units shall be available for complete inspection by the District Supervisor.
(3) The lessee shall provide information and data on the fitness of the drilling unit to perform the proposed drilling operation. The information shall be submitted with or prior to the submission of Form MMS-123, Application for Permit to Drill (APD), in accordance with § 250.414. The District Supervisor may require the submission of a third-party review of the design of drilling units which are of a unique design and/or not proven for use in the proposed environment if the District Supervisor believes that the information submitted by the lessee is insufficient to demonstrate suitability of the unit for use at the proposed drill site. A design Certified Verification Agent approved in accordance with § 250.903 of this part shall be used for any required third-party review.
(b)
(2) No later than May 31, 1989, diesel-engine air intakes shall be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines which are continuously attended shall be equipped with either remote operated manual or automatic shutdown devices. Diesel engines which are not continuously attended shall be equipped with automatic shutdown devices.
(c)
(d)
(e)
(2) Inclinational surveys shall be obtained on all vertical wells at intervals not exceeding 1,000 feet during the normal course of drilling. Directional surveys giving both inclination and azimuth shall be obtained on all directional wells at intervals not exceeding 500 feet during the normal course of drilling and at intervals not exceeding 100 feet in all portions of the hole when angle-changes are planned.
(3) On both vertical and directionally drilled wells, directional surveys giving both inclination and azimuth shall be obtained at intervals not exceeding 500 feet prior to or upon setting surface or intermediate casing, liners, and at total depth. Composite directional surveys shall be prepared with the interval shown from the bottom of the conductor casing or, in the absence of conductor casing, from the bottom of the drive or structural casing to total depth. In calculating all surveys, a correction from the true north to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north shall be made after making the magnetic-to-true-north correction. A composite dipmeter directional survey or a composite measurement-while-drilling (MWD) directional survey including a listing of the directionally computed inclinations and azimuths on a well classified as vertical will be acceptable as fulfilling the applicable requirements of this paragraph. In the event a composite MWD survey is run, a multishot survey shall be obtained at each casing point in order to confirm the MWD results.
(4) Wells are classified as vertical if the calculated average of inclination readings weighted by the respective interval lengths between readings from surface to drilled depth does not exceed 3 degrees from the vertical. When the calculated average inclination readings weighted by the length of the respective interval between readings from the surface to drilled depth exceeds 3 degrees, the well is classified as directional.
(5) The Regional Supervisor at the request of a holder of an adjoining lease may, for the protection of correlative rights, furnish a copy of the directional survey for a well drilled within 500 feet of the adjacent lease to that leaseholder.
(f)
(g)
(h)
(a)
(i) Drive or structural,
(ii) Conductor,
(iii) Surface,
(iv) Intermediate, and
(v) Production casing.
(2) The lessee shall case and cement all wells with a sufficient number of strings of casing and quantity and quality of cement in a manner necessary to prevent release of fluids from any stratum through the wellbore (directly or indirectly) into offshore waters, prevent communication between separate hydrocarbon-bearing strata, protect freshwater aquifers from contamination, support unconsolidated sediments, and otherwise provide a means of control of the formation pressures and fluids. Cement composition, placement techniques, and waiting time shall be designed and conducted so that the cement in place behind the bottom 500 feet of casing or total length of annular cement fill, if less, attains a minimum compressive strength of 500 pounds per square inch (psi). Cement placed across permafrost zones shall be designed to set before freezing and have a low heat of hydration.
(3) The lessee shall install casing designed to withstand the anticipated stresses imposed by tensile, compressive, and buckling loads; burst and collapse pressures; thermal effects; and combinations thereof. Safety factors in the casing program design shall be of sufficient magnitude to provide well control during drilling and to assure safe operations for the life of the well. Any portion of an annulus opposite a permafrost zone which is not protected by cement shall be filled with a liquid which has a freezing point below the minimum permafrost temperature to prevent internal freezeback and which is treated to minimize corrosion.
(4) In cases where cement has filled the annular space back to the mud line, the cement may be washed out or displaced to a depth not exceeding the depth of the structural casing shoe to facilitate casing removal upon well abandonment if the District Supervisor determines that subsurface protection against damage to freshwater aquifers and permafrost zones and against damage caused by adverse loads, pressures, and fluid flows is not jeopardized.
(5) If there are indications of inadequate cementing (such as lost returns, cement channeling, or mechanical failure of equipment), the lessee shall evaluate the adequacy of the cementing operations by pressure testing the casing shoe, running a cement bond log, running a temperature survey, or a combination thereof before continuing operations. If the evaluation indicates inadequate cementing, the lessee shall re-cement or take other remedial actions as approved by the District Supervisor.
(6) A pressure-integrity test shall be run below the surface casing, the intermediate casing(s), and liner(s) used as intermediate casing(s). The District Supervisor may require a pressure-integrity test to be run at the conductor casing shoe due to local geologic conditions or planned casing setting depths. Pressure-integrity tests shall be made after drilling new hole below the casing shoe and before drilling more than 50 feet of new hole below a respective casing string. These tests shall be conducted either by testing to formation leak-off or by testing to a predetermined equivalent mud weight as specified in the approved APD. A safe margin, as approved by the District Supervisor, shall be maintained between the mud weight in use and the equivalent mud weight at the casing shoe as determined in the pressure-integrity test. Drilling operations shall be suspended when the safe margin is not maintained. Pressure-integrity and pore-pressure test results and related hole-behavior observations, such as gas-cut mud and well kicks made during the course of drilling, shall be used in adjusting the drilling mud program and the approved setting depth of the next casing string. The results of all tests and of hole-behavior observations made during the course of drilling related to formation integrity and pore pressure shall be recorded in the driller's report.
(b)
(c)
(2)
(3)
(ii) For floating drilling operations, a lesser volume of cement may be used to prevent sealing the annular space between the conductor casing and surface casing if the District Supervisor determines that the uncemented space is necessary to provide protection from burst and collapse pressures which may be applied inadvertently to the annulus between casings during blowout preventer (BOP) testing operations. Any annular space open to the drilled hole shall be sealed in accordance with the requirements for abandonment in subpart G, Abandonment of Wells, of this part.
(d)
(2) Quantities of cement that cover and isolate all hydrocarbon-bearing zones in the well and isolate abnormal pressure intervals from normal pressure intervals shall be used. This requirement for isolation may be satisfied by squeeze cementing prior to completion, suspension of operations, or abandonment, whichever occurs first. Sufficient cement shall be used to provide annular fill-up to a minimum of 500 feet above the zones to be isolated or 500 feet above the casing shoe in wells where zonal coverage is not required.
(3) If a liner is to be used as an intermediate string below a surface casing string, it shall be lapped a minimum of 100 feet into the previous casing string and cemented as required for intermediate casing. When a liner is to be used as production casing below a surface casing string, it shall be extended to the surface and cemented to avoid surface casing being used as production casing.
(e)
(2) When a liner is to be used as production casing below intermediate casing, it shall be lapped a minimum of 100 feet into the previous casing string and cemented as required for the production casing.
(a) Prior to drilling the plug after cementing and in the cases of plugs in production casing strings and liners not planned to be subsequently drilled out, all casings, except the drive or structural casing, shall be pressure tested to 70 percent of the minimum internal-yield pressure of the casing or as otherwise approved or required by the District Supervisor. If the pressure declines more than 10 percent in 30 minutes or if there is another indication of a leak, the casing shall be recemented, repaired, or an additional casing string run and the casing pressure tested again. Additional remedial actions shall be taken until a satisfactory pressure test is obtained. The results of all casing pressure tests shall be recorded in the driller's report.
(b) Each production liner lap shall be tested to a minimum of 500 psi above formation fracture pressure at the shoe of the casing into which the liner is lapped, or as otherwise approved or required by the District Supervisor. The drilling liner-lap test pressure shall be equal to or exceed the pressure that will be encountered at the liner lap when conducting the planned pressure-integrity test below the liner shoe. The test results shall be recorded on the driller's report. If the test indicates an improper seal, remedial action shall be taken which provides a proper seal as demonstrated by a satisfactory pressure test.
(c) In the event of prolonged drill-pipe rotation within a casing string run to the surface or extended operations such as milling, fishing, jarring, washing over, and other operations which could damage the casing, the casing shall be pressure tested or evaluated by a logging technique such as a caliper log every 30 days. The evaluation results shall be submitted to the District Supervisor with a determination of effects of operations on the integrity of the casing for continued service during drilling operations and over the producing life of the well. If the integrity of the casing in the well has deteriorated to an unsafe level, remedial operations shall be conducted or additional casing set in accordance with a plan approved by the District Supervisor prior to continuing drilling operations.
(d) After cementing any string of casing other than the structural casing string, drilling shall not be resumed until there has been a time lapse of 8 hours under pressure for the conductor casing string and 12 hours under pressure for all other casing strings. Cement is considered under pressure if one or more float valves are shown to be holding the cement in place or when other means of holding pressure are used.
(a)
(b)
(c)
(d)
(1) An accumulator system which shall provide sufficient capacity to supply 1.5 times the volume of fluid necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a
(2) A backup to the primary accumulator-charging system which shall be automatic, supplied by a power source independent from the power source to the primary accumulator-charging system, and possess sufficient capability to close all BOP components and hold them closed.
(3) At least one operable remote BOP control station in addition to the one on the drilling floor. This control station shall be in a readily accessible location away from the drilling floor.
(4) A drilling spool with side outlets if side outlets are not provided in the body of the BOP stack to provide for separate kill and choke lines.
(5) For surface BOP systems, a choke and a kill line each equipped with two full-opening valves. At least one of the valves on the choke line shall be remotely controlled. At least one of the valves on the kill line shall be remotely controlled except that a check valve may be installed on the kill line in lieu of the remotely controlled valve provided two readily accessible manual valves are in place and the check valve is placed between the manual valves and the pump. For subsea BOP systems, a choke and a kill line each equipped with two full-opening valves. At least one of the valves on the choke line and at least one of the valves on the kill line shall be remotely controlled.
(6) A fill-up line above the uppermost preventer.
(7) A choke manifold suitable for the anticipated pressures to which it may be subjected, method of well control to be employed, surrounding environment, and corrosiveness, volume, and abrasiveness of fluids. The choke manifold shall also meet the following requirements:
(i) Manifold and choke equipment subject to well and/or pump pressure shall have a rated working pressure at least as great as the rated working pressure of the ram-type BOP's or as otherwise approved by the District Supervisor;
(ii) All components of the choke manifold system shall be protected from the danger, if any, of freezing by heating, draining, or filling with proper fluids; and
(iii) When buffer tanks are installed downstream of the choke assemblies for the purpose of manifolding the bleed lines together, isolation valves shall be installed on each line.
(8) Valves, pipes, flexible steel hoses, and other fittings upstream of, and including, the choke manifold with pressure ratings at least as great as the rated working pressure of the ram-type BOP's or as otherwise approved by the District Supervisor.
(9) A wellhead assembly with a rated working pressure that exceeds the anticipated surface pressure to which it may be subjected.
(10) The following system components:
(i) On a conventional drilling rig, a kelly cock installed below the swivel (upper kelly cock), essentially full-opening, and a similar valve of such design that it can be run through the BOP stack (strippable) installed at the bottom of the kelly (lower kelly cock). With a mud motor in service and while using drill pipe in lieu of a kelly, one kelly cock located above and one strippable kelly cock located below the joint of drill pipe employed in lieu of a kelly. On a top-drive system equipped with a remote controlled valve, a second and lower strippable valve of a conventional kelly cock or comparable type either manually or remotely controlled. All required manual and remotely controlled valves of a kelly cock or comparable type in a top-drive system must be essentially full-opening and tested according to the test pressure and test frequency as stated in § 250.407 of this part. A wrench to fit each manually operable valve in a conventional drilling rig, mud motor, and top-drive system shall be stored in a location readily accessible to the drilling crew.
(ii) An inside BOP and an essentially full-opening drill-string safety valve in the open position on the rig floor at all times while drilling operations are being conducted. These valves shall be
(iii) A safety valve available on the rig floor assembled with the proper connection to fit the casing string being run in the hole.
(11) Locking devices installed on the ram-type preventers.
(e)
(2) The BOP system shall include operable dual-pod control systems necessary to ensure proper and independent operation of the BOP system functions when drilling below the surface casing.
(3) Prior to the removal of the marine riser, the riser shall be displaced with seawater. Sufficient hydrostatic pressure or other suitable precautions, such as mechanical or cement plugs or closing the BOP, shall be maintained within the wellbore to compensate for the reduction in pressure and to maintain a safe controlled well condition.
(4) Any necessary repair or replacement of the BOP system or a system component after installation shall be accomplished under safe controlled conditions, (e.g., after casing has been cemented but prior to drilling out the casing shoe or by setting a cement plug, bridge plug, or a packer).
(5) When a subsea BOP system is to be used in an area which is subject to ice scour, the BOP stack shall be placed in an excavation (glory hole) of sufficient depth to assure that the top of the stack is below the deepest probable ice-scour depth.
(f)
(g)
(i) Two sets of pipe rams capable of sealing around the larger size drill string, and
(ii) One set of pipe rams capable of sealing around the smaller size drill string.
(2) Subsea BOP systems shall have blind-shear ram capability. Surface BOP systems shall have blind ram capability.
(a)
(1) When installed;
(2) Before 14 days have elapsed since your last BOP pressure test. You must begin to test your BOP system before 12 a.m. (midnight) on the 14th day following the conclusion of the previous test. However, the District Supervisor may require testing every 7 days if conditions or BOP performance warrant; and
(3) Before drilling out each string of casing or a liner. The District Supervisor may allow you to omit this test if you did not remove the BOP stack to run the casing string or liner and the required BOP-test pressures for the next section of the hole are not greater than the test pressures for the previous BOP test. You must indicate in your
(b)
(1) All low pressure tests must be between 200 and 300 psi. Any initial pressure above 300 psi must be bled back to a pressure between 200 and 300 psi before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero and reinitiate the test. You must conduct the low pressure test before the high pressure test.
(2) For ram-type BOP's, choke manifold, and other BOP equipment, the high pressure test must equal the rated working pressure of the equipment or the pressure otherwise approved by the District Supervisor; and
(3) For annular-type BOP's, the high pressure test must equal 70 percent of the rated working pressure of the equipment or the pressure otherwise approved by the District Supervisor.
(c)
(1) For surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if you record your test pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or on a digital recorder.
(2) If the equipment does not hold the required pressure during a test, you must remedy the problem and retest the affected component(s).
(d)
(1) Use water to test a surface BOP system;
(2) Stump test a subsurface BOP system before installation. You must use water to stump test a subsea BOP system. You may use drilling fluids to conduct subsequent tests of a subsea BOP system;
(3) Alternate tests between control stations and pods. If a control station or pod is not functional, you must suspend further drilling operations until that station or pod is operable;
(4) Pressure test the blind or blind-shear ram during a stump test and at all casing points. Additionally, the interval between any blind or blind-shear ram tests may not exceed 30 days;
(5) Function test annulars and rams every 7 days between pressure tests;
(6) Pressure-test variable bore-pipe rams against all sizes of pipe in use, excluding drill collars and bottom-hole tools;
(7) Test affected BOP components following the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack assembly;
(8) Actuate safety valves assembled with proper casing connections prior to running casing, and
(9) If you install casing rams, you must test the ram bonnet before running casing.
(e)
(f)
(g)
(h)
(1) Record BOP test pressures on pressure charts;
(2) Have your onsite representative certify (sign and date) BOP test charts and reports as correct;
(3) Document the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. You may reference a BOP test plan if it is available at the facility;
(4) Identify the control station or pod used during the test;
(5) Identify any problems or irregularities observed during BOP system testing and record actions taken to remedy the problems or irregularities;
(6) Retain all records, including pressure charts, driller's report, and referenced documents, pertaining to BOP tests, actuations, and inspections at the facility for the duration of drilling; and
(7) After drilling is completed, you must retain all the records listed in paragraph (h)(6) of this section for a period of 2 years at the facility, at the lessee's field office nearest the Outer Continental Shelf (OCS) facility, or at another location conveniently available to the District Supervisor.
(i)
(a) Well-control drills shall be conducted for each drilling crew in accordance with the following requirements:
(1) Drills shall be designed to acquaint each crew member with each member's function at the particular test station so each member can perform their functions promptly and efficiently.
(2) A well-control drill plan, applicable to the particular site, shall be prepared for each crew member outlining the assignments each member is to fulfill during the drill and establishing a prescribed time for the completion of each portion of the drill. A copy of the complete well-control drill plan shall be posted on the rig floor and/or bulletin board.
(3) The drill shall be carried out during periods of activity selected to minimize the risk of sticking the drill pipe or otherwise endangering the operation. In each of these drills, the reaction time of participants shall be measured up to the point when the designated person is prepared to activate the closing sequence of the BOP system. The total time for the crew to complete its entire drill assignment shall also be measured. This operation shall be recorded on the driller's report as “Well-Control Drill.” All drills shall be initiated by the toolpusher through the raising of the float on the pit-level device, activating the mud-return indicator, or its equivalent. This operation shall be performed at least once each week (well conditions permitting) with each crew. The drills shall be timed so they will cover a range of different operations which include on-bottom drilling and tripping. A diverter drill shall be developed and conducted in a similar manner for shallow operations.
(4)
(i) Detect kick and sound alarm;
(ii) Position kelly and tool joints so connections are accessible from floor, but tool joints are clear of sealing elements in BOP systems, stop pumps, check for flow, close in the well;
(iii) Record time;
(iv) Record drill-pipe pressure and casing pressure;
(v) Measure pit gain and mark new level;
(vi) Estimate volume of additional mud in pits;
(vii) Weight sample of mud from suction pit;
(viii) Check all valves on choke manifold and BOP system for correct position (open or closed);
(ix) Check BOP system components and choke manifold for leaks;
(x) Check flow line and choke exhaust lines for flow;
(xi) Check accumulator pressure;
(xii) Prepare to extinguish sources of ignition;
(xiii) Alert standby boat or prepare safety capsule for launching;
(xiv) Place crane operator on duty for possible personnel evacuation;
(xv) Prepare to lower escape ladders and prepare other abandonment devices for possible use;
(xvi) Determine materials needed to circulate out kick; and
(xvii) Time drill and enter drill report on driller's report.
(5)
(i) Detect kick and sound alarm;
(ii) Install safety valve, close safety valve;
(iii) Position pipe, prepare to close annular preventer;
(iv) Install inside preventer, open safety valve;
(v) Record time;
(vi) Record casing pressure;
(vii) Check all valves on choke manifold and BOP system for correct position (open or closed);
(viii) Check for leaks on BOP system component and choke manifold;
(ix) Check flow line and choke exhaust lines for flow;
(x) Check accumulator pressure;
(xi) Prepare to extinguish sources of ignition;
(xii) Alert standby boat or prepare safety capsule for launching;
(xiii) Place crane operator on duty for possible personnel evacuation;
(xiv) Prepare to lower escape ladders and prepare other abandonment devices for possible use;
(xv) Prepare to strip back to bottom; and
(xvi) Time drill and enter drill report on driller's report.
(b) A well-control drill may be required by a Minerals Management Service (MMS) authorized representative after consulting with the lessee's senior representative present.
(a) When drilling a conductor or surface hole, all drilling units shall be equipped with a diverter system consisting of a diverter sealing element, diverter lines, and control systems unless otherwise approved by the District Supervisor for floating drilling operations. The diverter system shall be designed, installed, and maintained so as to divert gases, water, mud, and other materials away from the facilities and personnel.
(b) No later than May 31, 1990, diverter systems shall be in compliance with the requirements of this section. The requirements applicable to diverters which were in effect April 1, 1988 shall remain in effect until May 31, 1990.
(c) The diverter system shall be equipped with remote-controlled valves in the flow and vent lines that can be operated from at least one remote-control station in addition to the one on the drilling floor. Any valve used in a diverter system shall be full-opening. No manual or butterfly valve shall be installed in any part of the diverter system. There shall be a minimum number of turns in the vent line(s) downstream of the spool outlet flange and the radius of curvature of turns shall be as large as practicable. All right-angle and sharp turns shall be targeted. Flexible hose may be used for diverter lines instead of rigid pipe if the flexible hose has integral end couplings. The entire diverter system shall be firmly anchored and supported to prevent whipping and vibration. All diverter control instruments and lines shall be protected from physical damage from thrown and falling objects.
(d) For drilling operations conducted with a surface wellhead configuration, the following shall apply:
(1) If the diverter system utilizes only one spool outlet, branch lines shall be installed to provide downwind diversion capability; and
(2) No spool outlet or diverter line internal diameter shall be less than 10 inches, except that dual spool outlets are acceptable provided that each outlet has a minimum internal diameter of 8 inches and that both outlets are piped to overboard lines and that each line downstream of the changeover nipple at the spool has a minimum internal diameter of 10 inches.
(e) For drilling operations conducted where a floating or semisubmersible type of drilling vessel is used and drilling fluids are circulated to the drilling vessel, the following shall apply:
(1) If the diverter system utilizes only one spool outlet, branch lines shall be installed to provide downwind diversion capability;
(2) No spool outlet or diverter line internal diameter shall be less than 12 inches; and
(3) Dynamically positioned drill ships may be equipped with a single vent line provided appropriate vessel heading is maintained to allow for downwind diversion.
(f) The diverter sealing element and diverter valves shall be pressure tested to a minimum of 200 psi when nippled up on conductor casing with a surface wellhead configuration. No more than 7 days shall elapse between subsequent similar pressure tests. For surface and subsea wellhead configurations, the diverter sealing element, diverter valves, and diverter-control systems, including the remote control system, shall be actuation-tested and the vent lines flow tested when first installed. Subsequent actuation tests shall be conducted not less than once every 24-hour period thereafter alternating between control stations. All pressure test, flow test, and actuation results shall be recorded in the driller's report.
(g) Diverter systems and components for use in subfreezing conditions shall be suitable for use under these conditions.
(a)
(b)
(i) There is no indication of influx of formation fluids prior to starting to pull the drill pipe from the hole.
(ii) The weight of the returning mud is essentially the same as the weight of the mud entering the hole. In the event that the returning mud is lighter than the entering mud by a weight differential equal to or greater than 0.2 pounds per gallon (1.5 pounds per cubic foot), the mud shall be circulated until a volume of drilling mud equal to the annular volume is displaced, and the mud properties measured to assure that there has been no influx of gas or liquid.
(iii) Other mud properties recorded on the daily drilling log are within the limits established by the approved mud program.
(2) When mud in the hole is circulated, the driller's report shall be so noted.
(3) When coming out of the hole with drill pipe, the annulus shall be filled with mud before the change in mud level decreases the hydrostatic pressure by 75 psi, or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe and drill collars that may be pulled prior to filling the hole and the equivalent mud volume shall be calculated and posted near the driller's station. A mechanical, volumetric, or electronic device for measuring the amount of mud required to fill the hole shall be utilized.
(4) Drill pipe and downhole tool running and pulling speeds shall be at controlled rates so as not to induce an influx of formation fluids from the effects of swabbing nor cause a loss of drilling fluid and corresponding hydrostatic pressure decrease from the effects of surging.
(5) When there is an indication of swabbing or influx of formation fluids, the safety devices and measures necessary to control the well shall be employed. The mud shall be circulated and conditioned, on or near bottom, unless well or mud conditions prevent running the drill pipe back to the bottom.
(6) For each casing string, the maximum pressure to be contained under the BOP shall be posted near the driller's station.
(7) In areas where permafrost and/or hydrate zones may be present or are known to be present, drilling fluid temperatures shall be controlled or other measures taken to drill safely through those zones.
(8) An operable mud-gas separator and operable degasser shall be installed in the mud system prior to commencement of drilling operations and shall be maintained for use throughout the drilling of the well.
(9) The mud in the hole shall be circulated or reverse-circulated prior to pulling the drill-stem test tools from the hole. If circulating out test fluid is not feasible, test fluids may be bullheaded out of the drill-stem test string
(c)
(2) The following mud-system monitoring equipment shall be installed with derrick floor indicators and used when mud returns are established and throughout subsequent drilling operations:
(i) Recording mud-pit level indicator to determine mud-pit volume gains and losses. This indicator shall include both a visual and an audible warning device.
(ii) Mud-volume measuring device to accurately determine mud volumes required to fill the hole on trips.
(iii) Mud-return indicator devices which indicate the relationship between mud-return flow rate and pump discharge rate. This indicator shall include both a visual and an audible warning device.
(iv) Gas-detecting equipment to monitor the drilling mud returns with indicators located in the mud-logging compartment or on the rig floor. If the indicators are only in the mud-logging compartment, there shall be a means of immediate communication with the rig floor, and the gas-detecting equipment shall be continually manned. If the indicators are on the rig floor only, an audible alarm shall be installed.
(d)
(2) Daily inventories of mud and mud materials including weight materials and additives at the drill site shall be recorded and those records maintained at the well site.
(3) Drilling operations shall be suspended in the absence of sufficient quantities of mud and mud materials to maintain well control.
(e)
(1) Be ventilated with high-capacity mechanical ventilation systems capable of replacing the air once every 5 minutes or 1.0 cubic feet of air-volume flow per minute per square foot of area, whichever is greater, unless such ventilation is provided by natural means. If not continuously activated, mechanical ventilation systems shall be activated on signal from gas detectors that are operational at all times indicating the presence of 1 percent or more of gas by volume.
(2) Be maintained at a negative pressure relative to an adjacent area if mechanical ventilation is installed to meet the requirements in paragraph (e)(1) of this section and discharges may be hazardous. The negative pressure areas shall be protected with at least one of the following: (i) A pressure-sensitive alarm, (ii) open-door alarms on each access to the area, (iii) automatic door-closing devices, (iv) air locks, or (v) other devices as approved by the District Supervisor.
(3) Be fitted with gas detectors and alarms except in open areas where adequate ventilation is provided by natural means.
(4) Be equipped with either explosion-proof or pressurized electrical equipment to prevent the ignition of explosive gases. Where air is used for pressuring, the air intake shall be located outside of, and as far as practicable from, hazardous areas.
(5) Mechanical ventilation systems shall be fitted with alarms which are activated upon a failure of the system.
(6) Gas detection systems shall be tested for operation and recalibrated at a frequency such that no more than 90 days shall elapse between tests.
A downhole safety device such as a cement plug, bridge plug, or packer shall be timely installed when drilling operations are interrupted by events such as those which force evacuation of the drilling crew, prevent station keeping, or require repairs to major drilling or well-control equipment. In floating drilling operations, the use of blind-shear rams or pipe rams and an inside BOP may be approved by the District Supervisor in lieu of the above requirements if supported by evidence of special circumstances and/or the lack of sufficient time.
When geological and engineering information available in a field enables a District Supervisor to determine specific operating requirements appropriate to wells to be drilled in the field, field drilling rules may be established on the initiative of the District Supervisor, or in response to a request from a lessee. Such rules may modify the requirements of this subpart. After field drilling rules have been established, development wells to which such rules apply shall be drilled in accordance with such rules and other requirements of this subpart. Field drilling rules may be amended or cancelled for cause at any time upon the initiative of the District Supervisor or upon the approval of a request by a lessee.
(a) The lessee shall provide onsite supervision of drilling operations on a 24-hour per day basis.
(b) From the time drilling operations are initiated and until the well is completed or abandoned, a member of the drilling crew or the toolpusher shall maintain rig-floor surveillance continuously, unless the well is secured with BOP's, bridge plugs, packers, or cement plugs.
(c) Lessee and drilling contractor personnel must be trained and qualified according to Subpart O of this part. Records of specific training which lessee and drilling contractor personnel have successfully completed, the dates of completion, and the names and dates of the courses shall be maintained at the drill site.
(a) Prior to commencing the drilling of a well under an approved Exploration Plan, Development and Production Plan, or Development Operations Coordination Document, the lessee shall file a Form MMS-123, APD, with the District Supervisor for approval. Prior to commencing operations, written approval from the District Supervisor must be received by the lessee unless oral approval has been given pursuant to § 250.140.
(b) The APD's for wells to be drilled from mobile drilling units shall include the following:
(1) An identification of the maximum environmental and operational conditions the rig is designed to withstand.
(2) Applicable current documentation of operational limitations imposed by the American Bureau of Shipping classification or other appropriate classification society and either a U.S. Coast Guard Certificate of Inspection or a U.S. Coast Guard Letter of Compliance.
(3) For frontier areas, the design and operating limitations beyond which suspension, curtailment, or modification of drilling or rig operations are required (e.g., vessel motion, offset, riser angle, anchor tensions, wind speed, wave height, currents, icing or ice-loading, settling, tilt or lateral movement, resupply capability) and the contingency plans which identify actions to be taken prior to exceeding the design or operating limitations of the rig.
(4) A program which provides for safety in drilling operations where a floating or semisubmersible type of
(c) The APD's shall include rated capacities of the proposed drilling unit and of major drilling equipment.
(d) In those areas which are subject to subfreezing conditions, the lessee shall furnish evidence that the drilling equipment, BOP system and components, drilling safety systems, diverter systems, and other associated equipment and materials are suitable for drilling operations under subfreezing conditions.
(e) After a drilling unit has been approved for use in an MMS District, the information listed in paragraphs (b) (1), (2), and (3), (c), and (d) of this section need not be resubmitted unless required by the District Supervisor or there are changes in equipment that affect the rated capacity of the unit.
(f) An APD shall include the following in addition to a fully completed Form MMS-123:
(1) A plat, drawn to a scale of 2,000 feet to the inch, showing the surface and subsurface location of the well to be drilled and of all the wells previously drilled in the vicinity from which information is available. Locations shall be indicated in feet from the block line.
(2) The design criteria considered for the well and for well control, including the following:
(i) Pore pressures.
(ii) Formation fracture gradients.
(iii) Potential lost circulation zones.
(iv) Mud weights.
(v) Casing setting depths.
(vi) Anticipated surface pressures (which for purposes of this section are defined as the pressure which can reasonably be expected to be exerted upon a casing string and its related wellhead equipment). In the calculation of an anticipated surface pressure, the lessee shall take into account the drilling, completion, and producing conditions. The lessee shall consider mud densities to be used below various casing strings, fracture gradients of the exposed formations, casing setting depths, total well depth, formation fluid type, and other pertinent conditions. Considerations for calculating anticipated surface pressure may vary for each segment of the well. The lessee shall include as a part of the statement of anticipated surface pressures the calculations used to determine these pressures during the drilling phase and the completion phase, including the anticipated surface pressure used for production string design.
(vii) If a shallow hazards site survey is conducted, the lessee shall submit with or prior to the submittal of the APD, two copies of a summary report describing the geological and manmade conditions present. The lessee shall also submit two copies of the site maps and data records identified in the survey strategy.
(viii) Permafrost zones, if applicable.
(3) A BOP equipment program including the following:
(i) The pressure rating of BOP equipment.
(ii) A well-control procedure for use of the annular preventer for those wells where the anticipated surface pressure exceeds the rated working pressure of the annular preventer.
(iii) A description of subsea BOP accumulator system or other type of closing system proposed for use.
(iv) A schematic drawing of the diverter system to be used (plan and elevation views) showing spool outlet internal diameter(s); diverter-line lengths and diameters, burst strengths, and radius of curvature at each turn; valve type, size, working pressure rating, and location; the control instrumentation logic; and the operating procedure to be used by lessee or contractor personnel.
(v) A schematic drawing of the BOP stack showing the inside diameter of the BOP stack, and the number of annular, pipe ram, variable-bore pipe
(4) A casing program including the following:
(i) Casing size, weight, grade, type of connection, and setting depth;
(ii) Casing design safety factors for tension, collapse, and burst with the assumptions made to arrive at these values; and
(iii) In areas containing permafrost, casing programs that incorporate setting depths for conductor and surface casing based on the anticipated depth of the permafrost at the proposed well location and which utilize the current state-of-the-art methods to safely drill and set casing. The casing program shall provide protection from thaw subsidence and freezeback effect, proper anchorage, and well control.
(5) The drilling prognosis including the following:
(i) Projected plans for coring at specified depths;
(ii) Projected plans for logging;
(iii) Estimated depths to the top of significant marker formations; and
(iv) Estimated depths at which encounters with significant porous and permeable zones containing fresh water, oil, gas, or abnormally pressured water are expected.
(6) A cementing program including type and amount of cement in cubic feet to be used for each casing string.
(7) A mud program including the minimum quantities of mud and mud materials, including weight materials, to be kept at the site.
(8) A directional survey program for directionally drilled wells.
(9) A plot of the estimated pore pressures and formation fracture gradients and the proposed mud weights and casing setting depths on the same sheet.
(10) A H
(11) Such other information as may be required by the District Supervisor.
(g) Public information copies of the APD shall be submitted in accordance with § 250.190 of this part.
(a) Notices of the lessee's intention to change plans, make changes in major drilling equipment, deepen or plug back a well, or engage in similar activities and subsequent reports pertaining to such operations shall be submitted to the District Supervisor on Form MMS-124, Sundry Notices and Reports on Wells. Prior to commencing operations, written approval must be received from the District Supervisor unless oral approval is obtained.
(b) The Form MMS-124 submitted shall contain a detailed statement of the proposed work that will materially change from the approved work described in the APD. Information submitted shall include the present status of the well, including the production string or last string of casing, the well depth, the present production zones and productive capability, and all other information specified on Form MMS-124. Within 30 days after completion of the work, a subsequent detailed report of all the work done and the results obtained shall be submitted.
(c) A Form MMS-124 with a plat, certified by a registered land surveyor, shall be filed as soon as the well's final surveyed surface location, water depth, and the rotary kelly bushing elevation have been determined.
(d) Public information copies of Sundry Notices and Reports on Wells shall be submitted in accordance with § 250.190 of this part.
(a) Complete and accurate records for each well and of all well operations shall be retained for a period of 2 years at the lessee's field office nearest the OCS facility or at another location conveniently available to the District Supervisor. The records shall contain a description of any significant malfunction or problem; all the formations penetrated; the content and character of oil, gas, and other mineral deposits and water in each formation; the kind, weight, size, grade, and setting depth of casing; all well logs and surveys run
(b) When drilling operations are suspended, or temporarily prohibited under the provisions of § 250.170 of this part, the lessee shall, within 30 days after termination of the suspension or temporary prohibition or within 30 days after the completion of any activities related to the suspension or prohibition, transmit to the District Supervisor duplicate copies of the records of all activities related to and conducted during the suspension or temporary prohibition on, or attached to, Form MMS-125, Well Summary Report, or Form MMS-124, as appropriate.
(c) Upon request by the Regional or District Supervisor, the lessee shall furnish the following:
(1) Copies of the records of any of the well operations specified in paragraph (a) of this section;
(2) Paleontological reports identifying microscopic fossils by depth and/or washed samples of drill cuttings normally maintained by the lessee for paleontological determinations;
(3) Copies of the daily driller's report at a frequency as determined by the District Supervisor. Items to be reported include spud dates, casing setting depths, cement quantities, casing characteristics, pressure integrity tests, mud weights, kicks, lost returns, and any unusual activities; and
(4) Legible, exact copies of service company reports on cementing, perforating, acidizing, analyses of cores, testing, or other similar services.
(d) As soon as available, the lessee shall transmit copies (field or final prints of individual runs) of logs or charts of electrical, radioactive, sonic, and other well-logging operations, directional-well surveys, and analyses of cores. Composite logs of multiple runs and directional-well surveys shall be transmitted to the District Supervisor in duplicate as soon as available but not later than 30 days after completion of each well.
(e) If the drilling unit moves from the wellbore prior to completing the well, the lessee shall submit to the District Supervisor copies of the well records with completed Form MMS-124, within 30 days after moving from the wellbore.
(f) If the Regional or District Supervisor determines that circumstances warrant, the lessee shall submit any other reports and records of operations, including paleontological interpretations based upon identification of microscopic fossils, in the manner and form prescribed by the Regional or District Supervisor.
(g) Records relating to the drilling of a well shall be retained for a period of 90 days after drilling operations are completed. Records relating to the completion of a well or of any workover activity which materially alters the completion configuration or materially affects or alters a hydrocarbon-bearing zone shall be kept until the well is permanently plugged and abandoned.
(a)
(1) Take all necessary and feasible precautions and measures to protect personnel from the toxic effects of H
(2) Follow your approved contingency plan.
(b)
(1) Drilling, logging, coring, testing, or producing operations have confirmed the absence of H
(2) Drilling in the surrounding areas and correlation of geological and seismic data with equivalent stratigraphic units have confirmed an absence of H
(c)
(1) Request and obtain an approved classification for the area from the Regional Supervisor before you begin operations. Classifications are “H
(2) Submit your request with your application for permit to drill;
(3) Support your request with available information such as geologic and geophysical data and correlations, well logs, formation tests, cores and analysis of formation fluids; and
(4) Submit a request for reclassification of a zone when additional data indicate a different classification is needed.
(d)
(e)
(f)
(1) Safety procedures and rules that you will follow concerning equipment, drills, and smoking;
(2) Training you provide for employees, contractors, and visitors;
(3) Job position and title of the person responsible for the overall safety of personnel;
(4) Other key positions, how these positions fit into your organization, and what the functions, duties, and responsibilities of those job positions are;
(5) Actions that you will take when the concentration of H
(6) Briefing areas where personnel will assemble during an H
(7) Criteria you will use to decide when to evacuate the facility and procedures you will use to safely evacuate all personnel from the facility by vessel, capsule, or lifeboat. If you use helicopters during H
(8) Procedures you will use to safely position all vessels attendant to the facility. Indicate where you will locate the vessels with respect to wind direction. Include the distance from the facility and what procedures you will use to safely relocate the vessels in an emergency;
(9) How you will provide protective-breathing equipment for all personnel, including contractors and visitors;
(10) The agencies and facilities you will notify in case of a release of H
(11) The medical personnel and facilities you will use if needed, their addresses, and telephone numbers;
(12) H
(i) All vessels, flare outlets, wellheads, and other equipment handling production containing H
(ii) Approximate maximum concentration of H
(iii) Location of all H
(13) Operational conditions when you expect to flare gas containing H
(14) Your assessment of the risks to personnel during flaring and what precautionary measures you will take;
(15) Primary and alternate methods to ignite the flare and procedures for sustaining ignition and monitoring the status of the flare (i.e., ignited or extinguished);
(16) Procedures to shut off the gas to the flare in the event the flare is extinguished;
(17) Portable or fixed sulphur dioxide (SO
(18) Increased monitoring and warning procedures you will take when the SO
(19) Personnel protection measures or evacuation procedures you will initiate when the SO
(20) Engineering controls to protect personnel from SO
(21) Any special equipment, procedures, or precautions you will use if you conduct any combination of drilling, well-completion, well-workover, and production operations simultaneously.
(g)
(1)
(i) Before beginning work at the facility; and
(ii) Each year, within 1 year after completion of the previous class.
(2)
(i) You must have documentation of this training at the facility where the individual is employed; or
(ii) The employee must carry a training completion card.
(3)
(i) Trained employees or contractors transferred from another facility must attend a supplemental briefing on your H
(ii) Visitors who will remain on your facility more than 24 hours must receive the training required for employees by paragraph (g)(4) of this section; and
(iii) Visitors who will depart before spending 24 hours on the facility are exempt from the training required for employees, but they must, upon arrival, complete a briefing that includes:
(A) Information on the location and use of an assigned respirator; practice in donning and adjusting the assigned respirator; information on the safe briefing areas, alarm system, and hazards of H
(B) Instructions on their responsibilities in the event of an H
(4)
(i) Hazards of H
(ii) Proper use of safety equipment which the employee may be required to use;
(iii) Location of protective breathing equipment, H
(iv) Restrictions and corrective measures concerning beards, spectacles, and contact lenses in conformance with ANSI Z88.2;
(v) Basic first-aid procedures applicable to victims of H
(vi) Location of:
(A) The first-aid kit on the facility;
(B) Resuscitators; and
(C) Litter or other device on the facility.
(vii) Meaning of all warning signals.
(5)
(h)
(i) Conduct a drill for each person at the facility during normal duty hours at least once every 7-day period. The drills must consist of a dry-run performance of personnel activities related to assigned jobs.
(ii) At a safety meeting or other meetings of all personnel, discuss drill performance, new H
(2)
(i) Drilling, well-completion, and well-workover operations at the facility until operations are completed; and
(ii) Production operations at the facility or at the nearest field office for 1 year.
(i)
(2)
(i) You must display warning signs at all times on facilities with wells capable of producing H
(ii) In addition to the signs, you must activate audible alarms and display flags or activate flashing red lights when atmospheric concentration of H
(3)
(4)
(5)
(6)
(7)
(i) Illuminate all signs and flags at night and under conditions of poor visibility; and
(ii) Use warning devices that are suitable for the electrical classification of the area.
(8)
(j)
(i) Be capable of sensing a minimum of 10 ppm of H
(ii) Activate audible and visual alarms when the concentration of H
(2)
(i) Bell nipple;
(ii) Mud-return line receiver tank (possum belly);
(iii) Pipe-trip tank;
(iv) Shale shaker;
(v) Well-control fluid pit area;
(vi) Driller's station;
(vii) Living quarters; and
(viii) All other areas where H
(3)
(4)
(i) When you pull a wet string of drill pipe or workover string;
(ii) When circulating bottoms-up after a drilling break;
(iii) During cementing operations;
(iv) During logging operations; and
(v) When circulating to condition mud or other well-control fluid.
(5)
(i) You must have a sensor in rooms, buildings, deck areas, or low-laying deck areas not otherwise covered by paragraph (j)(2) of this section, where atmospheric concentrations of H
(ii) You must have a sensor in buildings where personnel have their living quarters;
(iii) You must have a sensor within 10 feet of each vessel, compressor, wellhead, manifold, or pump, which could release enough H
(iv) You may use one sensor to detect H
(v) You do not need to have sensors near wells that are shut in at the master valve and sealed closed;
(vi) When you determine where to place sensors, you must consider:
(A) The location of system fittings, flanges, valves, and other devices subject to leaks to the atmosphere; and
(B) Design factors, such as the type of decking and the location of fire walls; and
(vii) The District Supervisor may require additional sensors or other monitoring capabilities, if warranted by site specific conditions.
(6)
(i) Personnel trained to calibrate the particular H
(ii) If the results of any functional test are not within 2 ppm or 10 percent, whichever is greater, of the applied concentration, recalibrate the instrument.
(7)
(i) When conducting drilling, drill stem testing, well-completion, or well-workover operations in areas classified as H
(ii) When conducting production operations, test all detectors at least every 14 days between tests.
(iii) If equipment requires calibration as a result of two consecutive functional tests, the District Supervisor may require that H
(8)
(i) You must maintain records of testing and calibrations (in the drilling or production operations report, as applicable) at the facility to show the present status and history of each device, including dates and details concerning:
(A) Installation;
(B) Removal;
(C) Inspection;
(D) Repairs;
(E) Adjustments; and
(F) Reinstallation.
(ii) Records must be available for inspection by MMS personnel.
(9)
(10)
(11)
(i) Monitor the SO
(ii) Take readings at least hourly and at any time personnel detect SO
(iii) Implement the personnel protective measures specified in the H
(iv) Calibrate devices every 3 months if you use fixed or portable electronic sensing devices to detect SO
(12)
(13)
(i) Provide all personnel, including contractors and visitors on a facility, with immediate access to self-contained pressure-demand-type respirators with hoseline capability and breathing time of at least 15 minutes.
(ii) Design, select, use, and maintain respirators to conform to ANSI Z88.2, American National Standard for Respiratory Protection.
(iii) Make available at least two voice-transmission devices, which can be used while wearing a respirator, for use by designated personnel.
(iv) Make spectacle kits available as needed.
(v) Store protective-breathing equipment in a location that is quickly and easily accessible to all personnel.
(vi) Label all breathing-air bottles as containing breathing-quality air for human use.
(vii) Ensure that vessels attendant to facilities carry appropriate protective-breathing equipment for each crew member. The District Supervisor may require additional protective-breathing equipment on certain vessels attendant to the facility.
(viii) During H
(ix) As appropriate to the particular operation(s), (production, drilling,
(k)
(i) Portable H
(ii) Retrieval ropes with safety harnesses to retrieve incapacitated personnel from contaminated areas;
(iii) Chalkboards and/or note pads for communication purposes located on the rig floor, shale-shaker area, the cement-pump rooms, well-bay areas, production processing equipment area, gas compressor area, and pipeline-pump area;
(iv) Bull horns and flashing lights; and
(v) At least three resuscitators on manned facilities, and a number equal to the personnel on board, not to exceed three, on normally unmanned facilities, complete with face masks, oxygen bottles, and spare oxygen bottles.
(2)
(i) Use only explosion-proof ventilation devices;
(ii) Install ventilation devices in areas where H
(iii) Provide movable ventilation devices in work areas. The movable ventilation devices must be multidirectional and capable of dispersing H
(3)
(i) A first-aid kit of appropriate size and content for the number of personnel on the facility; and
(ii) At least one litter or an equivalent device.
(l)
(m)
(1) You may use either water- or oil-base muds in accordance with § 250.300(b)(1).
(2) If you use water-base well-control fluids, and if ambient air sensors detect H
(3) If the concentration detected by air sensors in over 20 ppm, personnel conducting the tests must don protective-breathing equipment conforming to paragraph (j)(13) of this section.
(4) You must maintain on the facility sufficient quantities of additives for the control of H
(i)
(ii)
(iii)
(5) You must degas well-control fluids containing H
(n)
(1) Contain the well-fluid influx by shutting in the well and pumping the fluids back into the formation.
(2) Control the kick by using appropriate well-control techniques to prevent formation fracturing in an open hole within the pressure limits of the well equipment (drill pipe, work string, casing, wellhead, BOP system, and related equipment). The disposal of H
(o)
(1) Before starting a well test, conduct safety meetings for all personnel who will be on the facility during the test. At the meetings, emphasize the use of protective-breathing equipment, first-aid procedures, and the Contingency Plan. Only competent personnel who are trained and are knowledgeable of the hazardous effects of H
(2) Perform well testing with the minimum number of personnel in the immediate vicinity of the rig floor and with the appropriate test equipment to safely and adequately perform the test. During the test, you must continuously monitor H
(3) Not burn produced gases except through a flare which meets the requirements of paragraph (q)(6) of this section. Before flaring gas containing H
(4) Use downhole test tools and wellhead equipment suitable for H
(5) Use tubulars suitable for H
(6) Use surface test units and related equipment that is designed for H
(p)
(1) Use tubulars and other equipment, casing, tubing, drill pipe, couplings, flanges, and related equipment that is designed for H
(2) Use BOP system components, wellhead, pressure-control equipment, and related equipment exposed to H
(3) Use temporary downhole well-security devices such as retrievable packers and bridge plugs that are designed for H
(4) When producing in zones bearing H
(5) Keep the use of welding to a minimum during the installation or modification of a production facility. Welding must be done in a manner that ensures resistance to sulfide stress cracking.
(q)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(13)
(14)
Well-completion operations shall be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased and not leased), the national security or defense, or the marine, coastal, or human environment.
When used in this subpart, the following term shall have the meaning given below:
The movement of well-completion rigs and related equipment on and off a platform or from well to well on the same platform, including rigging up and rigging down, shall be conducted in a safe manner. All wells in the same well-bay which are capable of producing hydrocarbons shall be shut in below the surface with a pump-through-type tubing plug and at the surface with a closed master valve prior to moving well-completion rigs and related equipment, unless otherwise approved by the District Supervisor. A closed surface-controlled subsurface safety valve of the pump-through type may be used in lieu of the pump-through-type tubing plug, provided that the surface control has been locked out of operation. The well from which the rig or related equipment is to be moved shall also be equipped with a back-pressure valve prior to removing the blowout preventer (BOP) system and installing the tree.
When well-completion operations are conducted on a platform where there are other hydrocarbon-producing wells or other hydrocarbon flow, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station.
When a well-completion operation is conducted in zones known to contain hydrogen sulfide (H
No subsea well completion shall be commenced until the lessee obtains written approval from the District Supervisor in accordance with § 250.513 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will adequately control the well and permit safe production operations.
Prior to engaging in well-completion operations, crew members shall be instructed in the safety requirements of the operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available at the facility for review by MMS representatives.
Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the proposed operations. Prior to moving a well-completion rig or equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the corrosion protection, age of platform, and previous stresses to the platform.
No later than May 31, 1989, diesel engine air intakes shall be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines which are continuously attended shall be equipped with either remote operated manual or automatic-shutdown devices. Diesel engines which are not continuously attended shall be equipped with automatic-shutdown devices.
After May 31, 1989, all units being used for well-completion operations which have both a traveling block and a crown block shall be equipped with a safety device which is designed to prevent the traveling block from striking the crown block. The device shall be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational check shall be entered in the operations log.
When geological and engineering information available in a field enables the District Supervisor to determine specific operating requirements, field well-completion rules may be established on the District Supervisor's initiative or in response to a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-completion rules have been established, well-completion operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field well-completion rules may be amended or canceled for cause at any time upon the initiative of the District Supervisor or upon the request of a lessee.
(a) No well-completion operation shall begin until the lessee receives written approval from the District Supervisor. If completion is planned and the data are available at the time the Application for Permit to Drill, Form MMS-123 (see § 250.414 of this part), is submitted, approval for a well completion may be requested on that form. If the completion has not been approved or if the completion objective or plans have significantly changed, approval for such operations shall be requested on Form MMS-124, Sundry Notices and Reports on Wells.
(b) The following information shall be submitted with Form MMS-124 (or with Form MMS-123):
(1) A brief description of the well-completion procedures to be followed, a statement of the expected surface pressure, and type and weight of completion fluids;
(2) A schematic drawing of the well showing the proposed producing zone(s) and the subsurface well-completion equipment to be used;
(3) For multiple completions, a partial electric log showing the zones proposed for completion, if logs have not been previously submitted; and
(4) When the well-completion is in a zone known to contain H
(c) Within 30 days after completion, Form MMS-125, Well Summary Report, including a schematic of the tubing and subsurface equipment, shall be submitted to the District Supervisor.
(d) Public information copies of Form MMS-125 shall be submitted in accordance with § 250.190.
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-completion operations and shall not be left unattended at any time unless the well is shut in and secured.
(b) The following well-control-fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.
(c) When coming out of the hole with drill pipe, the annulus shall be filled with well-control fluid before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hole shall be utilized.
(a) The BOP system and system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The working pressure rating of the BOP system and BOP system components shall exceed the expected surface pressure to which they may be subjected. If the expected surface pressure exceeds the rated working pressure of the annular preventer, the lessee shall submit with Form MMS-124 or Form MMS-123, as appropriate, a well-control procedure that indicates how the annular preventer will be utilized, and the pressure limitations that will be applied during each mode of pressure control.
(b) The minimum BOP system for well-completion operations shall include the following:
(1) Three preventers, when the expected surface pressure is less than 5,000 psi, consisting of an annular preventer, one preventer equipped with pipe rams, and one preventer equipped with blind or blind-shear rams.
(2) Four preventers, when the expected surface pressure is 5,000 psi or greater, or for multiple tubing strings consisting of an annular preventer, two preventers equipped with pipe rams, and one preventer equipped with blind or blind-shear rams. When dual tubing strings are being handled simultaneously, dual pipe rams shall be installed on one of the pipe-ram preventers.
(3) When tapered drill string is used, the minimum BOP system shall include either of the following:
(i) Four preventers, when the expected surface pressure is less than 5,000 psi, consisting of an annular preventer, two sets of pipe rams, one capable of sealing around the larger size drill string and one capable of sealing around the smaller size drill string (one set of variable bore rams may be substituted for the two sets of pipe rams), and one preventer equipped with blind or blind shear rams; or
(ii) Five preventers, when the expected surface pressure is 5,000 psi or greater, consisting of an annular preventer, two sets of pipe rams capable of sealing around the larger size drill string, one set of pipe rams capable of sealing around the smaller size drill string (one set of variable bore rams may be substituted for one set of pipe
(c) The BOP systems for well completions shall be equipped with the following:
(1) A hydraulic-actuating system that provides sufficient accumulator capacity to supply 1.5 times the volume necessary to close all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. No later than December 1, 1988, accumulator regulators supplied by rig air and without a secondary source of pneumatic supply, shall be equipped with manual overrides, or alternately, other devices provided to ensure capability of hydraulic operations if rig air is lost.
(2) A secondary power source, independent from the primary power source, with sufficient capacity to close all BOP system components and hold them closed.
(3) Locking devices for the pipe-ram preventers.
(4) At least one remote BOP-control station and one BOP-control station on the rig floor.
(5) A choke line and a kill line each equipped with two full opening valves and a choke manifold. At least one of the valves on the choke line shall be remotely controlled. At least one of the valves on the kill line shall be remotely controlled, except that a check valve on the kill line in lieu of the remotely controlled valve may be installed provided that two readily accessible manual valves are in place and the check valve is placed between the manual valves and the pump. This equipment shall have a pressure rating at least equivalent to the ram preventers.
(d) An inside BOP or a spring-loaded, back-pressure safety valve and an essentially full-opening, work-string safety valve in the open position shall be maintained on the rig floor at all times during well-completion operations. A wrench to fit the work-string safety valve shall be readily available. Proper connections shall be readily available for inserting valves in the work string.
(a)
(1) When installed; and
(2) Before 14 days have elapsed since your last BOP pressure test. You must begin to test your BOP system before 12 a.m. (midnight) on the 14th day following the conclusion of the previous test. However, the District Supervisor may require testing every 7 days if conditions or BOP performance warrant.
(b)
(1) All low pressure tests must be between 200 and 300 psi. Any initial pressure above 300 psi must be bled back to a pressure between 200 and 300 psi before starting the test. If the initial pressure exceeds 500 psi, you must bleed back to zero and reinitiate the test. You must conduct the low pressure test before the high pressure test.
(2) For ram-type BOP's, choke manifold, and other BOP equipment, the high pressure test must equal the rated working pressure of the equipment.
(3) For annular-type BOP's, the high pressure test must equal 70 percent of the rated working pressure of the equipment.
(c)
(1) For surface BOP systems and surface equipment of a subsea BOP system, a 3-minute test duration is acceptable if you record your test pressures on the outermost half of a 4-hour chart, on a 1-hour chart, or on a digital recorder.
(2) If the equipment does not hold the required pressure during a test, you must remedy the problem and retest the affected component(s).
(d)
(1) Use water to test the surface BOP system;
(2) Stump test a subsurface BOP system before installation. You must use water to stump test a subsea BOP system. You may use drilling or completion fluids to conduct subsequent tests of a subsea BOP system;
(3) Alternate tests between control stations and pods. If a control station or pod is not functional, you must suspend further completion operations until that station or pod is operable;
(4) Pressure test the blind or blind-shear ram at least every 30 days;
(5) Function test annulars and rams every 7 days;
(6) Pressure-test variable bore-pipe rams against all sizes of pipe in use, excluding drill collars and bottom-hole tools; and
(7) Test affected BOP components following the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack assembly;
(e)
(f)
(g)
(h)
(i)
(1) Record BOP test pressures on pressure charts;
(2) Have your onsite representative certify (sign and date) BOP test charts and reports as correct;
(3) Document the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. You may reference a BOP test plan if it is available at the facility;
(4) Identify the control station or pod used during the test;
(5) Identify any problems or irregularities observed during BOP system and equipment testing and record actions taken to remedy the problems or irregularities;
(6) Retain all records including pressure charts, driller's report, and referenced documents pertaining to BOP tests, actuations, and inspections at the facility for the duration of the completion activity; and
(7) After completion of the well, you must retain all the records listed in paragraph (i)(6) of this section for a period of 2 years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the District Supervisor.
(j)
(a) No tubing string shall be placed in service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use.
(b) In the event of prolonged operations such as milling, fishing, jarring, or washing over that could damage the casing, the casing shall be pressure-tested, calipered, or otherwise evaluated every 30 days and the results submitted to the District Supervisor.
(c) When the tree is installed, the wellhead shall be equipped so that all annuli can be monitored for sustained pressure. If sustained casing pressure is
(d) Wellhead, tree, and related equipment shall have a pressure rating greater than the shut-in tubing pressure and shall be designed, installed, used, maintained, and tested so as to achieve and maintain pressure control. New wells completed as flowing or gas-lift wells shall be equipped with a minimum of one master valve and one surface safety valve, installed above the master valve, in the vertical run of the tree.
(e) Subsurface safety equipment shall be installed, maintained, and tested in compliance with § 250.801 of this part.
Well-workover operations shall be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the Outer Continental Shelf (OCS) including any mineral deposits (in areas leased and not leased), the national security or defense, or the marine, coastal, or human environment.
When used in this subpart, the following terms shall have the meanings given below:
(a) Cutting paraffin;
(b) Removing and setting pump-through-type tubing plugs, gas-lift valves, and subsurface safety valves which can be removed by wireline operations;
(c) Bailing sand;
(d) Pressure surveys;
(e) Swabbing;
(f) Scale or corrosion treatment;
(g) Caliper and gauge surveys;
(h) Corrosion inhibitor treatment;
(i) Removing or replacing subsurface pumps;
(j) Through-tubing logging (diagnostics);
(k) Wireline fishing; and
(l) Setting and retrieving other subsurface flow-control devices.
The movement of well-workover rigs and related equipment on and off a platform or from well to well on the same platform, including rigging up and rigging down, shall be conducted in a safe manner. All wells in the same well-bay which are capable of producing hydrocarbons shall be shut in below the surface with a pump-through-type tubing plug and at the surface with a closed master valve prior to moving well-workover rigs and related equipment unless otherwise approved by the District Supervisor. A closed surface-controlled subsurface safety valve of the pump-through-type may be used in lieu of the pump-through-type tubing plug provided that the surface control has been locked out of operation. The well to which a well-workover rig or related equipment is to be moved shall also be equipped with a back-pressure valve prior to removing the tree and installing and testing the blowout-preventer (BOP) system. The well from which a well-workover rig or related equipment is to be moved shall also be equipped with a back pressure valve prior to removing the BOP system and installing the tree. Coiled tubing units, snubbing units, or wireline units may be moved onto a platform without shutting in wells.
When well-workover operations are conducted on a well with the tree removed, an emergency shutdown system (ESD) manually controlled station shall be installed near the driller's console or well-servicing unit operator's work station, except when there is no other hydrocarbon-producing well or other hydrocarbon flow on the platform.
When a well-workover operation is conducted in zones known to contain hydrogen sulfide (H
No subsea well-workover operation including routine operations shall be commenced until the lessee obtains written approval from the District Supervisor in accordance with § 250.613 of this part. That approval shall be based upon a case-by-case determination that the proposed equipment and procedures will maintain adequate control of the well and permit continued safe production operations.
Prior to engaging in well-workover operations, crew members shall be instructed in the safety requirements of the operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available at the facility for review by a Minerals Management Service representative.
Derricks, masts, substructures, and related equipment shall be selected, designed, installed, used, and maintained so as to be adequate for the potential loads and conditions of loading that may be encountered during the operations proposed. Prior to moving a well-workover rig or well-servicing equipment onto a platform, the lessee shall determine the structural capability of the platform to safely support the equipment and proposed operations, taking into consideration the corrosion protection, age of the platform, and previous stresses to the platform.
No later than May 31, 1989, diesel engine air intakes shall be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines which are continuously attended shall be equipped with either remote operated manual or automatic shutdown devices. Diesel engines which are not continuously attended shall be equipped with automatic shutdown devices.
After May 31, 1989, all units being used for well-workover operations which have both a traveling block and a crown block shall be equipped with a safety device which is designed to prevent the traveling block from striking the crown block. The device shall be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational check shall be entered in the operations log.
When geological and engineering information available in a field enables the District Supervisor to determine specific operating requirements, field well-workover rules may be established on the District Supervisor's initiative or in response to a request from a lessee. Such rules may modify the specific requirements of this subpart. After field well-workover rules have been established, well-workover operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field well-
(a) No well-workover operation except routine ones, as defined in § 250.601 of this part, shall begin until the lessee receives written approval from the District Supervisor. Approval for such operations shall be requested on Form MMS-124, Sundry Notices and Reports on Wells.
(b) The following information shall be submitted with Form MMS-124:
(1) A brief description of the well-workover procedures to be followed, a statement of the expected surface pressure, and type and weight of workover fluids;
(2) When changes in existing subsurface equipment are proposed, a schematic drawing of the well showing the zone proposed for workover and the workover equipment to be used; and
(3) Where the well-workover is in a zone known to contain H
(c) The following additional information shall be submitted with Form MMS-124 if completing to a new zone is proposed:
(1) Reason for abandonment of present producing zone including supportive well test data, and
(2) A statement of anticipated or known pressure data for the new zone.
(d) Within 30 days after completing the well-workover operation, except routine operations, Form MMS-124, Sundry Notices and Reports on Wells, shall be submitted to the District Supervisor, showing the work as performed. In the case of a well-workover operation resulting in the initial recompletion of a well into a new zone, a Form MMS-125, Well Summary Report, shall be submitted to the District Supervisor and shall include a new schematic of the tubing subsurface equipment if any subsurface equipment has been changed.
The following requirements apply during all well-workover operations with the tree removed:
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be continuously monitored during well-workover operations and shall not be left unattended at anytime unless the well is shut in and secured.
(b) When coming out of the hole with drill pipe or a workover string, the annulus shall be filled with well-control fluid before the change in such fluid level decreases the hydrostatic pressure 75 pounds per square inch (psi) or every five stands of drill pipe or workover string, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe or workover string and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hold shall be utilized.
(c) The following well-control-fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP;
(2) A well-control, fluid-volume measuring device for determining fluid volumes when filling the hole on trips; and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.
(a) The BOP system, system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The working pressure rating of the BOP system and system components shall exceed the expected surface pressure to which they may be subjected. If the expected surface pressure exceeds the rated working pressure of the annular preventer, the lessee shall submit with Form MMS-124, requesting approval of the well-workover operation, a well-control procedure that indicates how the annular preventer will be utilized, and the pressure limitations that will be applied during each mode of pressure control.
(b) The minimum BOP system for well-workover operations with the tree removed shall include of the following:
(1) Three preventers, when the expected surface pressure is less than 5,000 psi, consisting of an annular preventer, one preventer equipped with pipe rams, and one preventer equipped with blind or blind-shear rams.
(2) Four preventers, when the expected surface pressure is 5,000 psi or greater, or for multiple tubing strings consisting of an annular preventer, two preventers equipped with pipe rams, and one preventer equipped with blind or blind-shear rams. When dual tubing strings are being handled simultaneously, dual pipe rams shall be installed on one of the pipe-ram preventers.
(3) When a tapered drill string is used, the minimum BOP system shall include either of the following:
(i) Four preventers, when the expected surface pressure is less than 5,000 psi, consisting of an annular preventer, two sets of pipe rams, one capable of sealing around the larger size drill string, and one capable of sealing around the smaller size drill string (one set of variable bore rams may be substituted for the two sets of pipe rams), and one preventer equipped with blind or blind-shear rams; or
(ii) Five preventers, when the expected surface pressure is 5,000 psi or greater, consisting of an annular preventer, two sets of pipe rams capable of sealing around the larger size drill string, one set of pipe rams capable of sealing around the smaller size drill string (one set of variable bore rams may be substituted for one set of pipe rams capable of sealing around the larger size drill string and the set of pipe rams capable of sealing around the smaller size drill string), and a preventer equipped with blind or blind-shear rams.
(c) The BOP systems for well-workover operations with the tree removed shall be equipped with the following:
(1) A hydraulic-actuating system that provides sufficient accumulator capacity to supply 1.5 times the volume necessary to close all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. No later than December 1, 1988, accumulator regulators supplied by rig air and without a secondary source of pneumatic supply, shall be equipped with manual overrides, or alternately, other devices provided to ensure capability of hydraulic operations if rig air is lost;
(2) A secondary power source, independent from the primary power source, with sufficient capacity to close all BOP system components and hold them closed;
(3) Locking devices for the pipe-ram preventers;
(4) At least one remote BOP-control station and one BOP-control station on the rig floor; and
(5) A choke line and a kill line each equipped with two full opening valves and a choke manifold. At least one of the valves on the choke-line shall be remotely controlled. At least one of the valves on the kill line shall be remotely controlled, except that a check valve on the kill line in lieu of the remotely controlled valve may be installed provided two readily accessible manual valves are in place and the check valve is placed between the manual valves and the pump. This equipment shall have a pressure rating at least equivalent to the ram preventers.
(d) The minimum BOP-system components for well-workover operations
(1) Two sets of pipe rams, and
(2) One set of blind rams.
(e) The minimum BOP-system components for well-workover operations with the tree in place and performed by manipulating spooled, nonjointed pipe through the wellhead, i.e., coiled-tubing operations, shall include the following:
(1) One set of pipe rams hydraulically operated,
(2) One two-way slip assembly hydraulically operated,
(3) One pipe-cutter assembly hydraulically operated,
(4) One set of blind rams hydraulically operated,
(5) One pipe-stripper assembly, and
(6) One spool with side outlets.
(f) The minimum BOP-system components for well-workover operations with the tree in place and performed by moving tubing or drill pipe in or out of a well under pressure utilizing equipment specifically designed for that purpose, i.e., snubbing operations, shall include the following:
(1) One set of pipe rams hydraulically operated, and
(2) Two sets of stripper-type pipe rams hydraulically operated with spacer spool.
(g) An inside BOP or a spring-loaded, back-pressure safety valve and an essentially full-opening, work-string safety valve in the open position shall be maintained on the rig floor at all times during well-workover operations when the tree is removed or during well-workover operations with the tree installed and using small tubing as the work string. A wrench to fit the work-string safety valve shall be readily available. Proper connections shall be readily available for inserting valves in the work string. The full-opening safety valve is not required for coiled tubing or snubbing operations.
(a) Prior to conducting high-pressure tests, all BOP system components shall be successfully tested to a low pressure of 200 to 300 psi. Ram-type BOP's, related control equipment, including the choke and kill manifolds, and safety valves shall be successfully tested to the rated working pressure of the BOP equipment or as otherwise approved by the District Supervisor. Variable bore rams shall be pressure-tested against all sizes of drill pipe in the well excluding drill collars. Surface BOP systems shall be pressure tested with water. The annular-type BOP shall be successfullly tested at 70 percent of its rated working pressure or as otherwise approved by the District Supervisor. Each valve in the choke and kill manifolds shall be successfully, sequentially pressure tested to the ram-type BOP test pressure.
(b) The BOP systems shall be tested at the following times:
(1) When installed;
(2) At least every 7 days, alternating between control stations and at staggered intervals to allow each crew to operate the equipment. If either control system is not functional, further operations shall be suspended until the nonfunctional, system is operable. The test every 7 days is not required for blind or blind-shear rams. The blind or blind-shear rams shall be tested at least once every 30 days during operation. A longer period between blowout preventer tests is allowed when there is a stuck pipe or pressure-control operation and remedial efforts are being performed. The tests shall be conducted as soon as possible and before normal operations resume. The reason for postponing testing shall be entered into the operations log.
(3) Following repairs that require disconnecting a pressure seal in the assembly, the affected seal will be pressure tested.
(c) All personnel engaged in well-workover operations shall participate in a weekly BOP drill to familiarize crew members with appropriate safety measures.
(d) The lessee shall record pressure conditions during BOP tests on pressure charts, unless otherwise approved
(e) The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP system, system components, and marine risers shall be recorded in the operations log. The BOP tests shall be documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an alternate, the documentation in the operations log may reference a BOP test plan that contains the required information and is retained on file at the facility.
(2) The control station used during the test shall be identified in the operations log. For a subsea system, the pod used during the test shall be identified in the operations log.
(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to remedy such problems or irregularities shall be noted in the operations log.
(4) Documentation required to be entered in the operation log may instead be referenced in the operations log. All records including pressure charts, operations log, and referenced documents pertaining to BOP tests, actuations, and inspections, shall be available for MMS review at the facility for the duration of well-workover activity. Following completion of the well-workover actity, all such records shall be retained for a period of 2 years at the facility, at the lessee's filed office nearest the OCS facility, or at another location conveniently available to the District Supervisor.
The lessee shall comply with the following requirements during well-workover operations with the tree removed:
(a) No tubing string shall be placed in service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use.
(b) In the event of prolonged operations such as milling, fishing, jarring, or washing over that could damage the casing, the casing shall be pressure tested, calipered, or otherwise evaluated every 30 days and the results submitted to the District Supervisor.
(c) When reinstalling the tree, the wellhead shall be equiped so that all annuli can be monitored for sustained pressure. If sustained casing pressure is observed on a well, the lessee shall immediately notify the District Supervisor.
(d) Wellhead, tree, and related equipment shall have a pressure rating greater than the shut-in tubing pressure and shall be designed, installed, used, maintained, and tested so as to achieve and maintain pressure control. The tree shall be equipped with a minimum of one master valve and one surface safety valve in the vertical run of the tree when it is reinstalled.
(e) Subsurface safety equipment shall be installed, maintained, and tested in compliance with § 250.801 of this part.
The lessee shall comply with the following requirements during routine, as defined in § 250.601 of this part, and nonroutine wireline workover operations:
(a) Wireline operations shall be conducted so as to minimize leakage of well fluids. Any leakage that does occur shall be contained to prevent pollution.
(b) All wireline perforating operations and all other wireline operations where communication exists between the completed hydrocarbon-bearing zone(s) and the wellbore shall use a lubricator assembly containing at least one wireline valve.
(c) When the lubricator is initially installed on the well, it shall be successfully pressure tested to the expected shut-in surface pressure.
(a) The lessee shall abandon all wells in a manner to assure downhole isolation of hydrocarbon zones, protection of freshwater aquifers, clearance of sites so as to avoid conflict with other uses of the Outer Continental Shelf (OCS), and prevention of migration of formation fluids within the wellbore or to the seafloor. Any well which is no longer used or useful for lease operations shall be plugged and abandoned in accordance with the provisions of this subpart. However, no production well shall be abandoned until its lack of capacity for further profitable production of oil, gas, or sulphur has been demonstrated to the satisfaction of the District Supervisor. No well shall be plugged if the plugging operations would jeopardize safe and economic operations of nearby wells, unless the well poses a hazard to safety or the environment.
(b) Lessees must plug and abandon all well bores, remove all platforms or other facilities, and clear the ocean of all obstructions to other users. This obligation:
(1) Accrues to the lessee when the well is drilled, the platform or other facility is installed, or the obstruction is created; and
(2) Is the joint and several responsibility of all lessees and owners of operating rights under the lease at the time the obligation accrues, and of each future lessee or owner of operating rights, until the obligation is satisfied under the requirements of this part.
The lessee shall not commence abandonment operations without prior approval of the District Supervisor. The lessee shall submit a request on Form MMS-124, Sundry Notices and Reports on Wells, for approval to abandon a well and a subsequent report of abandonment within 30 days from completion of the work in accordance with the following:
(a)
(b)
(a)
(b)
(1) A cement retainer and a cement plug shall be set. The cement retainer shall have effective back-pressure control and shall be set not less than 50 feet and not more than 100 feet above the casing shoe. The cement plug shall extend at least 100 feet below the casing shoe and at least 50 feet above the retainer.
(2) If lost circulation conditions have been experienced or are anticipated, a permanent-type bridge plug may be placed within the first 150 feet above the casing shoe with a minimum of 50 feet of cement on top of the bridge plug. This bridge plug shall be tested in accordance with paragraph (g) of this section.
(c)
(1) A cement retainer and a cement plug shall be set. The cement retainer shall have effective back-pressure control and shall be set not less than 50 feet and not more than 100 feet above the top of the perforated interval. The cement plug shall extend at least 100 feet below the bottom of the perforated interval with 50 feet placed above the retainer.
(2) A permanent-type bridge plug shall be set within the first 150 feet above the top of the perforated interval with at least 50 feet of cement on top of the bridge plug.
(3) A cement plug which is at least 200 feet long shall be set by the displacement method with the bottom of the plug within the first 100 feet above the top of the perforated interval.
(d)
(1) A stub terminating inside a casing string shall be plugged with a cement plug extending at least 100 feet above and 100 feet below the stub. In lieu of setting a cement plug across the stub, the following methods are acceptable:
(i) A cement retainer or a permanent-type bridge plug shall be set not less than 50 feet above the stub and capped with at least 50 feet of cement, or
(ii) A cement plug which is at least 200 feet long shall be set with the bottom of the plug within 100 feet above the stub.
(2) If the stub is below the next larger string, plugging shall be accomplished as required to isolate zones or to isolate an open hole as described in paragraphs (a) and (b) of this section.
(e)
(f)
(g)
(1) The lessee shall place a minimum pipe weight of 15,000 pounds on the cement plug, cement retainer, or bridge plug. The cement placed above the bridge plug or retainer is not required to be tested.
(2) The lessee shall test the plug with a minimum pump pressure of 1,000 pounds per square inch with a result of no more than a 10-percent pressure drop during a 15-minute period.
(h)
(i)
(j)
(1) Fluid left in the hole adjacent to permafrost zones shall have a freezing point below the temperature of the permafrost and shall be treated to inhibit corrosion.
(2) The cement used for cement plugs placed across permafrost zones shall be designed to set before freezing and to have a low heat of hydration.
(a) Any drilling well which is to be temporarily abandoned shall meet the requirements for permanent abandonment (except for the provisions in §§ 250.702 (f) and (i), and 250.704) and the following:
(1) A bridge plug or a cement plug at least 100 feet in length shall be set at the base of the deepest casing string unless the casing string has been cemented and has not been drilled out. If a cement plug is set, it is not necessary for the cement plug to extend below the casing shoe into the open hole.
(2) A retrievable or a permanent-type bridge plug or a cement plug at least 100 feet in length, shall be set in the casing within the first 200 feet below the mud line.
(b) Subsea wellheads, casing stubs, or other obstructions above the seafloor remaining after temporary abandonment will be protected in such a manner as to allow commercial fisheries gear to pass over the structure without damage to the structure or fishing gear. Depending on water depth, nature and height of obstruction above the seafloor, and the types and periods of fishing activity in the area, the District Supervisor may waive this requirement.
(c) In order to maintain the temporarily abandoned status of a well, the lessee shall provide, within 1 year of the original temporary abandonment and at successive 1-year intervals thereafter, an annual report describing plans for reentry to complete or permanently abandon the well.
(d) Identification and reporting of subsea wellheads, casing stubs, or other obstructions extending above the mud line will be accomplished in accordance with the requirements of the U.S. Coast Guard.
(a) The lessees shall verify site clearance after abandonment by one or more of the following methods as approved by the District Supervisor:
(1) Drag a trawl in two directions across the location,
(2) Perform a diver search around the wellbore,
(3) Scan across the location with a side-scan or on-bottom scanning sonar, or
(4) Use other methods based on particular site conditions.
(b) Certification that the area was cleared of all obstructions, the date the work was performed, the extent of the area searched around the location, and the search method utilized shall be submitted on Form MMS-124.
Production safety equipment shall be designed, installed, used, maintained, and tested in a manner to assure the safety and protection of the human, marine, and coastal environments. Production safety systems operated in subfreezing climates shall utilize equipment and procedures selected with consideration of floating ice, icing, and
(a)
(b)
(c)
(d)
(1) Wells not previously equipped with surface-controlled SSSV's shall be so equipped when the tubing is first removed and reinstalled,
(2) The subsurface-controlled SSSV is installed in wells completed from a single-well or multiwell satellite caisson or seafloor completions, or
(3) The subsurface-controlled SSSV is installed in wells with a surface-controlled SSSV that has become inoperable and cannot be repaired without removal and reinstallation of the tubing.
(e)
(1) The device shall be installed at a depth of 100 feet or more below the seafloor within 2 days after production is established. When warranted by conditions such as permafrost, unstable bottom conditions, hydrate formation, or paraffins, an alternate setting depth of the subsurface safety device may be approved by the District Supervisor.
(2) Until a subsurface safety device is installed, the well shall be attended in the immediate vicinity so that emergency actions may be taken while the well is open to flow. During testing and inspection procedures, the well shall not be left unattended while open to production unless a properly operating subsurface-safety device has been installed in the well.
(3) The well shall not be open to flow while the subsurface safety device is removed, except when flowing of the well is necessary for a particular operation such as cutting paraffin, bailing sand, or similar operations.
(4) All SSSV's shall be inspected, installed, maintained, and tested in accordance with American Petroleum Institute Recommended Practice 14B, Recommended Practice for Design, Installation, and Operation of Subsurface Safety Valve Systems.
(f)
(g)
(h)
(2) The well shall be identified by a sign on the wellhead stating that the subsurface safety device has been removed. The removal of the subsurface safety device shall be noted in the records as required in § 250.804(b) of this part. If the master valve is open, a trained person shall be in the immediate vicinity of the well to attend the well so that emergency actions may be taken, if necessary.
(3) A platform well shall be monitored, but a person need not remain in the well-bay area continuously if the master valve is closed. If the well is on a satellite structure, it must be attended or a pump-through plug installed in the tubing at least 100 feet below the mud line and the master valve closed, unless otherwise approved by the District Supervisor.
(4) The well shall not be allowed to flow while the subsurface safety device is removed, except when flowing the well is necessary for that particular operation. The provisions of this paragraph are not applicable to the testing and inspection procedures in § 250.804 of this part.
(i)
(j)
(a)
(b)
(c)
(d)
(e)
(1) A schematic flow diagram showing tubing pressure, size, capacity, design working pressure of separators, flare scrubbers, treaters, storage tanks, compressors, pipeline pumps, metering devices, and other hydrocarbon-handling vessels.
(2) A schematic flow diagram (API RP 14C, Figure E1) and the related Safety Analysis Function Evaluation chart (API RP 14C, subsection 4.3c).
(3) A schematic piping diagram showing the size and maximum allowable working pressures as determined in accordance with API RP 14E, Design and Installation of Offshore Production Platform Piping Systems.
(4) Electrical system information including the following:
(i) A plan for each platform deck outlining all hazardous areas classified according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, and outlining areas in which potential ignition sources, other than electrical, are to be installed. The area outlined will include the following information:
(A) All major production equipment, wells, and other significant hydrocarbon sources and a description of the type of decking, ceiling, walls (e.g., grating or solid) and firewalls; and
(B) Location of generators, control rooms, panel boards, major cabling/conduit routes, and identification of the primary wiring method (e.g., type cable, conduit, or wire).
(ii) Elementary electrical schematic of any platform safety shut-down system with a functional legend.
(5) Certification that the design for the mechanical and electrical systems to be installed were approved by registered professional engineers. After these systems are installed, the lessee shall submit a statement to the District Supervisor certifying that new installations conform to the approved designs of this subpart.
(6) The design and schematics of the installation and maintenance of all fire- and gas-detection systems shall include the following:
(i) Type, location, and number of detection sensors;
(ii) Type and kind of alarms, including emergency equipment to be activated;
(iii) Method used for detection;
(iv) Method and frequency of calibration; and
(v) A functional block diagram of the detection system, including the electric power supply.
(a)
(b)
(i) Pressure relief valves shall be designed, installed, and maintained in accordance with applicable provisions of sections I, IV, and VIII of the ASME Boiler and Pressure Vessel Code. The relief valves shall conform to the valve-sizing and pressure-relieving requirements specified in these documents; however, the relief valves, except completely redundant relief valves, shall be set no higher than the maximum-allowable working pressure of the vessel. All relief valves and vents shall be piped in such a way as to prevent fluid from striking personnel or ignition sources.
(ii) Steam generators operating at less than 15 pounds per square inch gauge (psig) shall be equipped with a level safety low (LSL) sensor which will shut off the fuel supply when the water level drops below the minimum safe level. Steam generators operating at greater than 15 psig require, in addition to an LSL, a water-feeding device which will automatically control the water level.
(iii) The lessee shall use pressure recorders to establish the new operating pressure ranges of pressure vessels at any time when there is a change in operating pressures that requires new settings for the high-pressure shut-in sensor and/or the low-pressure shut-in sensor as provided herein. The pressure-recorder charts used to determine current operating pressure ranges shall be maintained at the lessee's field office nearest the OCS facility or at other locations conveniently available to the District Supervisor. The high-pressure shut-in sensor shall be set no higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the vessel. This setting shall also be set sufficiently below (5 percent or 5 psi, whichever is greater) the relief valve's set pressure to assure that the pressure source is shut in before the relief valve activates. The low-pressure shut-in sensor shall activate no lower than 15 percent or 5 psi, whichever is greater, below the lowest pressure in the operating range. The activation of low-pressure sensors on pressure vessels which operate at less than 5 psi shall be approved by the District Supervisor on a case-by-case basis.
(2)
(ii) If a well flows directly to the pipeline before separation, the flowline and valves from the well located upstream of and including the header inlet valve(s) shall have a working pressure equal to or greater than the maximum shut-in pressure of the well unless the flowline is protected by one of the following:
(A) A relief valve which vents into the platform flare scrubber or some other location approved by the District Supervisor. The platform flare scrubber shall be designed to handle, without liquid-hydrocarbon carryover to the flare, the maximum-anticipated flow of liquid hydrocarbons which may be relieved to the vessel.
(B) Two SSV's with independent high-pressure sensors installed with adequate volume upstream of any block valve to allow sufficient time for
(3)
(4)
(i) The manually operated ESD valve(s) shall be quick-opening and nonrestricted to enable the rapid actuation of the shutdown system. Only ESD stations at the boat landing may utilize a loop of breakable synthetic tubing in lieu of a valve.
(ii) Closure of the SSV shall not exceed 45 seconds after automatic detection of an abnormal condition or actuation of an ESD. The surface-controlled SSSV shall close in not more than 2 minutes after the shut-in signal has closed the SSV. Design-delayed closure time greater than 2 minutes shall be justified by the lessee based on the individual well's mechanical/production characteristics and be approved by the District Supervisor.
(iii) A schematic of the ESD which indicates the control functions of all safety devices for the platforms shall be maintained by the lessee on the platform or at the lessee's field office nearest the OCS facility or other location conveniently available to the District Supervisor.
(5)
(ii)
(6)
(7)
(i) A Pressure Safety High (PSH), a Pressure Safety Low (PSL), a Pressure Safety Valve (PSV), and a Level Safety High (LSH), and an LSL to protect each interstage and suction scrubber.
(ii) A Temperature Safety High (TSH) on each compressor discharge cylinder.
(iii) The PSH and PSL shut-in sensors and LSH shut-in controls protecting compressor suction and interstage scrubbers shall be designed to actuate automatic shutdown valves (SDV) located in each compressor suction and fuel gas line so that the compressor unit and the associated vessels can be isolated from all input sources. All automatic SDV's installed in compressor suction and fuel gas piping shall also be actuated by the shutdown of the prime mover. Unless otherwise approved by the District Supervisor, gas-well gas affected by the closure of the automatic SDV on a compressor suction shall be diverted to the pipeline or shut in at the wellhead.
(iv) A blowdown valve is required on the discharge line of all compressor installations of 1,000 horsepower (746 kilowatts) or greater.
(8)
(i) A firewater system consisting of rigid pipe with firehose stations or
(ii) Fuel or power for firewater pump drivers shall be available for at least 30 minutes of run time during a platform shut-in. If necessary, an alternate fuel or power supply shall be installed to provide for this pump-operating time unless an alternate firefighting system has been approved by the District Supervisor.
(iii) A firefighting system using chemicals may be used in lieu of a water system if the District Supervisor determines that the use of a chemical system provides equivalent fire-protection control.
(iv) A diagram of the firefighting system showing the location of all firefighting equipment shall be posted in a prominent place on the facility or structure.
(v) For operations in subfreezing climates, the lessee shall furnish evidence to the District Supervisor that the firefighting system is suitable for the conditions.
(9)
(ii) All detection systems shall be capable of continuous monitoring. Fire-detection systems and portions of combustible gas-detection systems related to the higher gas concentration levels shall be of the manual-reset type. Combustible gas-detection systems related to the lower gas-concentration level may be of the automatic-reset type.
(iii) A fuel-gas odorant or an automatic gas-detection and alarm system is required in enclosed, continuously manned areas of the facility which are provided with fuel gas. Living quarters and doghouses not containing a gas source and not located in a classified area do not require a gas detection system.
(iv) The District Supervisor may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(v) Fire- and gas-detection systems shall be an approved type, designed and installed in accordance with API RP 14C, API RP 14G, and API RP 14F, Design and Installation of Electrical Systems for Offshore Production Platforms.
(10)
(11)
(c)
(2) When wells are disconnected from producing facilities and blind flanged, equipped with a tubing plug, or the master valves have been locked closed, compliance is not required with the provisions of API RP 14C or this regulation concerning the following:
(i) Automatic fail-close SSV's on wellhead assemblies, and
(ii) The PSH and PSL shut-in sensors in flowlines from wells.
(3) When pressure or atmospheric vessels are isolated from production facilities (e.g., inlet valve locked closed or inlet blind-flanged) and are to remain isolated for an extended period of time, safety device compliance with API RP 14C or this subpart is not required.
(4) All open-ended lines connected to producing facilities and wells shall be plugged or blind-flanged, except those lines designed to be open-ended such as flare or vent lines.
(d)
(a)
(1) Testing requirements for subsurface safety devices are as follows:
(i) Each surface-controlled subsurface safety device installed in a well, including such devices in shut-in and injection wells, shall be tested in place for proper operation when installed or reinstalled and thereafter at intervals not exceeding 6 months. If the device does not operate properly, or if a liquid leakage rate in excess of 200 cubic centimeters per minute or a gas leakage rate in excess of 5 cubic feet per minute is observed, the device shall be removed, repaired and reinstalled, or replaced. Testing shall be in accordance with API RP 14B to ensure proper operation.
(ii) Each subsurface-controlled SSSV installed in a well shall be removed, inspected, and repaired or adjusted, as necessary, and reinstalled or replaced at intervals not exceeding 6 months for those valves not installed in a landing nipple and 12 months for those valves installed in a landing nipple.
(iii) Each tubing plug installed in a well shall be inspected for leakage by opening the well to possible flow at intervals not exceeding 6 months. If a liquid leakage rate in excess of 200 cubic centimeters per minute or a gas leakage rate in excess of 5 cubic feet per minute is observed, the device shall be removed, repaired and reinstalled, or replaced. An additional tubing plug may be installed in lieu of removal.
(iv) Injection valves shall be tested in the manner as outlined for testing tubing plugs in paragraph (a)(1)(iii) of this section. Leakage rates outlined in paragraph (a)(1)(iii) of this section shall apply.
(2) All PSV's shall be tested for operation at least once every 12 months. These valves shall be either bench-tested or equipped to permit testing with an external pressure source. Weighted disk vent valves used as PSV's on atmospheric tanks may be disassembled and inspected in lieu of function testing.
(3) The following safety devices shall be tested at least once each calendar month, but at no time shall more than 6 weeks elapse between tests:
(i) All PSH and PSL,
(ii) All LSH and LSL controls,
(iii) All automatic inlet SDV's which are actuated by a sensor on a vessel or compressor, and
(iv) All SDV's in liquid discharge lines and actuated by vessel low-level sensors.
(4) All SSV's and USV's shall be tested for operation and for leakage at least once each calendar month, but at no time shall more than 6 weeks elapse between tests. The testing shall be in
(5) All flowline Flow Safety Valves (FSV) shall be checked for leakage at least once each calendar month, but at no time shall more than 6 weeks elapse between tests. The FSV's shall be tested for leakage in accordance with the test procedure specified in API RP 14C, appendix D, section D4, table D2, subsection D. If the leakage measured exceeds a liquid flow of 200 cubic centimeters per minute or a gas flow of 5 cubic feet per minute, the FSV's shall be repaired or replaced.
(6) The TSH shutdown controls installed on compressor installations which can be nondestructively tested shall be tested every 6 months and repaired or replaced as necessary.
(7) All pumps for firewater systems shall be inspected and operated weekly.
(8) All fire- (flame, heat, or smoke) detection systems shall be tested for operation and recalibrated every 3 months provided that testing can be performed in a nondestructive manner. Open flame or devices operating at temperatures which could ignite a methane-air mixture shall not be used. All combustible gas-detection systems shall be calibrated every 3 months.
(9) All TSH devices shall be tested at least once every 12 months, excluding those addressed in paragraph (a)(6) of this section and those which would be destroyed by testing. Burner safety low and flow safety low devices shall also be tested at least once every 12 months.
(10) The ESD shall be tested for operation at least once each calendar month, but at no time shall more than 6 weeks elapse between tests. The test shall be conducted by alternating ESD stations monthly to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation.
(11) Prior to the commencement of production, the lessee shall notify the District Supervisor when the lessee is ready to conduct a preproduction test and inspection of the integrated safety system. The lessee shall also notify the District Supervisor upon commencement of production in order that a complete inspection may be conducted.
(b)
Personnel installing, inspecting, testing, and maintaining these safety devices and personnel operating the production platforms shall be qualified in accordance with subpart O.
(a)
(i) Surface safety valves (SSV) and actuators;
(ii) Underwater safety valves (USV) and actuators; and
(iii) Subsurface safety valves (SSSV) and associated safety valve locks and landing nipples.
(2) Certified SPPE is equipment the manufacturer certifies as manufactured under a quality assurance program MMS recognizes. MMS considers all other SPPE as noncertified. MMS recognizes two quality assurance programs:
(i) ANSI/ASME SPPE-1, Quality Assurance and Certification of Safety and Pollution-Prevention Equipment Used in Offshore Oil and Gas Operations; and
(ii) API Spec Q1, Specification for Quality Programs.
(3) All SSV's and USV's must meet the technical specifications of API Spec 6A and 6AV1. All SSSV's must meet the technical specifications of API Spec 14A.
(b)
(2) On or after April 1, 1998:
(i) You may not install additional noncertified SPPE; and
(ii) When noncertified SPPE that is already in service requires offsite repair, remanufacturing, or hot work such as welding, you must replace it with certified SPPE.
(c)
Production operations in zones known to contain hydrogen sulfide (H
(a) The lessee shall design, fabricate, install, use, inspect, and maintain all platforms and structures (platforms) on the Outer Continental Shelf (OCS) to assure their structural integrity for the safe conduct of drilling, workover, and production operations, considering the specific environmental conditions at the platform location.
(b) All new fixed or bottom-founded platforms (i.e., platforms or other structures, e.g., single-well caissons, artificial islands), shall be designed, fabricated, installed, inspected, and maintained in accordance with all the requirements of this section and §§ 250.901 and 250.904 through 250.914 of this subpart. Applications submitted pursuant to § 250.901 shall require the approval by the Regional Supervisor prior to platform installation.
(c) All new platforms which meet any of the conditions listed below shall be subject to the Platform Verification Program and shall be designed, fabricated, and installed in accordance with the requirements of §§ 250.901 through 250.914 of this part.
(1) Platforms installed in water depths exceeding 400 feet,
(2) Platforms having natural periods in excess of 3 seconds,
(3) Platforms installed in areas of unstable bottom conditions,
(4) Platforms having configurations and designs which have not previously been used or proven for use in the area, or
(5) Platforms installed in seismically active areas.
(d) Major modification to any platform shall be subject to the requirements of this subpart and shall require the approval of the Regional Supervisor. Major modification means any structural changes which materially alter the approved plan or causes a major deviation from approved operations.
(e)(1) Major repairs of damage to any platform shall require the prior approval of the Regional Supervisor. Major repairs of damage means corrective operations involving structural members affecting the structural integrity of a portion or all of the platform.
(2) Under emergency conditions, repairs to primary structural elements may be made to restore an existing permitted condition without prior approval. The Regional Supervisor shall
(f) The requirements for an application for approval for the reuse or conversion of the use of an existing fixed or mobile platforms shall be determined on a case-by-case basis. An application shall be submitted to the Regional Supervisor for approval and shall include location, intended use, and demonstrate the adequacy of the design and structural condition of the platform.
(g) In addition to the requirements of this subpart, platform design, fabrication, and installation shall conform to API RP 2A, Recommended Practice For Planning, Designing, And Constructing Fixed Offshore Platforms, or American Concrete Institute (ACI) 357R, Guide for the Design and Construction of Fixed Offshore Concrete Structures, as appropriate. Alternative codes or rules may be utilized with approval of the Regional Supervisor. The requirements contained in these documents (API RP 2A and ACI 357R) are incorporated herein insofar as they do not conflict with other provisions of this subpart.
(a) All applications under the provisions of this subpart shall be submitted to the Regional Supervisor for approval. All significant changes or modifications to approved applications shall be submitted to the Regional Supervisor for approval.
(b) Applications for all new platforms or major modifications shall be submitted in triplicate and shall contain the following information:
(1) General platform information including the following:
(i) The platform designation, lease number, area name, and block number;
(ii) Longitude and latitude coordinates, Universal Transverse Mercator grid-system coordinates, state plane coordinates in the Lambert or Transverse Mercator Projection system, and a plat drawn to a scale of 1 inch = 2,000 feet showing surface location of the platform and distance from the nearest block lines;
(iii) Drawings, plats, front and side elevations of the entire platform, and plan views that clearly illustrate essential parts, i.e., number and location of well slots, design loadings of each deck, water depth, nominal size and thickness of all primary load-bearing jacket and deck structural members, and nominal size, makeup, thickness, and design penetration of piling;
(iv) Corrosion protection or durability details which consist of the corrosion-protection method; expected life; and durability criteria for the submerged, splash, and atmospheric zones; and
(v) In the Alaska OCS Region, the following additional information shall be submitted:
(A) Slope protection and berm elevation for manmade islands,
(B) Wall thickness with size and placement of major steel reinforcement for concrete-gravity structures,
(C) Shell thickness with size and location of major reinforcement members for steel-gravity structures, and
(D) A plan for periodic inspections of the installed platforms in accordance with § 250.912 of this part.
(2) A summary of environmental data, as addressed in § 250.904 of this part, which has a bearing on the platform's design, installation, and operation, e.g., wave heights and periods, current, vertical distribution of wind and gust velocities, water depth, storm and astronomical tide data, marine growth, snow and ice effects, and air and sea temperatures;
(3) Foundation information including the following:
(i) A geotechnical investigation report containing a brief summary of the major strata encountered at the location by bore holes presented in tabular form, a detailed subsurface profile illustrating results of field and laboratory testing, a listing of field and laboratory investigations and tests with a basic summary of resultant determinations, the identification of properties and conditions of the seabed and the subsoil, and the identification of any manmade hazards or obstructions;
(ii) A description of the effect of the environmental and functional loads on the foundation;
(iii) A determination, with supporting information, of the susceptibility of the area to soil movement and, if susceptible, an analysis of slope and soil stability;
(iv) A summary of the foundation design criteria as specified in § 250.909 of this part; and
(v) A summary of the seafloor survey results specified in § 250.909(b)(2) of this part.
(4) Structural information including the following:
(i) The design life of the platform and the basis for such determination.
(ii) A summary description of the design load conditions and design load combinations, taking into consideration the worst environmental and operational conditions anticipated over the service life of the platform.
(iii) A listing and description of the appropriate material specifications.
(iv) A description of the design methodologies, e.g., elastic, inelastic, and ultimate strength, used in design of the platform.
(v) A summary of pertinent derived factors of safety against failure for major structural members, e.g., unity check ratios exceeding 0.85 for steel-jacket platform members, indicated on “line” sketches of jacket sections.
(vi)(A) In the Alaska, Atlantic, and Pacific OCS Regions, a summary of the fatigue analysis as specified in §§ 250.905 through 250.909 of this part. The specific requirements for a fatigue analysis shall be determined by the Regional Supervisor on a case-by-case basis to determine the adequacy of the design and to assure the structural integrity of the platform.
(B) In the Gulf of Mexico OCS Region, a summary of the fatigue analysis as specified in §§ 250.905 through 250.909 of this part. A fatigue analysis shall be performed for each steel template, pile-supported platform with natural periods greater than 3 seconds, and for each platform to be fabricated of high-strength steel (i.e., over 50 thousand pounds per square inch minimum yield) where components of high-strength steel are subjected to cyclic loading. The specific requirements for a fatigue analysis for other platforms shall be determined by the Regional Supervisor on a case-by-case basis to determine adequacy of the design and to assure the structural integrity of the platform.
(c) The information shall be submitted with or subsequent to the submittal of an Exploration Plan or Development and Production Plan. Additional detailed data and information may be required by the Regional Supervisor when needed to determine the adequacy of the design.
(d) The lessee shall have detailed structural plans as called for in paragraph (b)(1)(iii) of this section and specifications for new platforms or other structures and major modifications certified by a registered professional structural engineer or civil engineer specializing in structural design. The lessee shall also sign, date, and submit the following certification: Lessee certifies that the design of the structure/modification has been certified by a registered professional structural or a civil engineer specializing in structural design, and the structure/modification will be fabricated, installed, and maintained as described in the application and any approved modification thereto. Certified design and as built plans and specifications will be on file at———.
(e) The lessee shall notify the Regional Supervisor at least 1 week prior to transporting the platform to the installation site.
(a)
(b)
(i) A nomination of a Certified Verification Agent (CVA) who shall conduct specified reviews in accordance with § 250.903 of this part,
(ii) The CVA qualification statement consisting of the following:
(A) Previous experience in third-party verification or experience in the design, fabrication, and/or installation of offshore oil and gas platforms, manmade islands, or other marine structures;
(B) Technical capabilities of the individual or the primary staff to be associated with the CVA functions for the specific project;
(C) Size and type of organization or corporation;
(D) In-house availability of, or access to, appropriate technology, i.e., computer programs and hardware and testing materials and equipment;
(E) Ability to perform the CVA functions for the specific project considering current commitments; and
(F) Previous experience with MMS requirements and procedures.
(iii) The level of work to be performed by the CVA, and
(iv) A list of documents to be furnished to the CVA.
(2)
(i) All design documentation specified in § 250.901(b) of this part, and
(ii) Abstracts of the computer programs used in the design process.
(3)
(i) Structural tolerances,
(ii) Welding procedures,
(iii) Material (concrete, gravel, or silt) placement methods,
(iv) Fabrication standards,
(v) Material quality-control procedures,
(vi) Methods and extent of nondestructive examinations (NDE) for welds and materials, and
(vii) Quality assurance procedures.
(4)
(c)
(d)
(a)
(1)
(ii) The design verification shall be conducted by, or be under the direct
(iii) The CVA shall consider the applicable provisions of §§ 250.904 through 250.911 of this part and use good engineering practice in conducting an independent assessment of the adequacy of all proposed planning criteria, environmental data, load determinations, stress analyses, material designations, soil and foundation conditions, safety factors, and other pertinent parameters of the proposed design.
(iv) Interim reports shall be submitted by the CVA, as appropriate, to the Regional Supervisor and the lessee.
(v) Upon completion of the design verification, a final report shall be prepared which summarizes the material reviewed by the CVA and the findings and includes a recommendation that the Regional Supervisor either accept, request modification(s), or reject the proposed design. In addition, the report shall include the particulars of how, by whom, and when the independent review was conducted and any special comments considered necessary. The final report shall be submitted to the lessee and, in triplicate, to the Regional Supervisor within 6 weeks of the receipt of the design data or from the date the approval to act as a CVA was issued, whichever is later.
(2)
(i) Periodic onsite inspections shall be made while fabrication is in progress. The following of the fabrication items, as appropriate, shall be verified:
(A) Quality control by lessee and builder,
(B) Fabrication site facilities,
(C) Material quality and identification methods,
(D) Fabrication procedures specified in the approved plan and adherence to such procedures,
(E) Welder and welding procedure qualification and identification,
(F) Structural tolerances specified and adherence to those tolerances,
(G) The NDE requirements and evaluation results of the specified examinations,
(H) Destructive testing requirements and results,
(I) Repair procedures,
(J) Installation of corrosion-protection systems and splash-zone protection,
(K) Erection procedures to ensure that overstressing of structural members does not occur,
(L) Alignment procedures,
(M) Dimensional check of the overall structure, and
(N) Status of quality-control records at various stages of fabrication.
(ii) The CVA shall consider the applicable provisions of §§ 250.904 through 250.911 of this part and use good engineering practice in conducting an independent assessment of the adequacy of the fabrication of the platform or major modification.
(iii) Interim reports shall be submitted by the CVA, as appropriate, to the Regional Supervisor and the lessee.
(iv) If the CVA finds that fabrication procedures are changed or design specifications are modified, the lessee shall be informed. If the lessee prefers to accept the modifications as informed by the CVA, the Regional Supervisor shall also be informed.
(v) A final report shall be prepared by the CVA covering the adequacy of the entire fabrication phase giving details of how, by whom, and when the independent monitoring activities were conducted and providing any special comments considered necessary. The final report is not required to cover aspects of the fabrication already included in interim reports. The final report shall describe the CVA's activities during the verification process, summarize the findings, contain a confirmation or denial of compliance with the design specifications and the approved fabrication plan, and a recommendation to accept or reject the fabrication. The report shall be submitted to the lessee and, in triplicate, to the Regional Supervisor immediately after completion of the fabrication of the platform.
(3)
(i) The CVA shall consider the applicable provisions of §§ 250.904 through 250.911 of this part and use good engineering practice in conducting an independent assessment of the adequacy of the installation activities. The following parts of the overall installation process, as appropriate, shall be verified:
(A) Loadout and initial flotation operations, if any;
(B) Towing operations to the specified location;
(C) Launching and uprighting operations;
(D) Submergence operations;
(E) Pile installation; and
(F) Final deck and/or component installation.
(ii) The CVA shall observe the installation activities, spot-check equipment, procedures, and recordkeeping, as necessary, to determine compliance with §§ 250.904 through 250.911 of this part and the approved plans, and immediately report to the Regional Supervisor and the lessee any discrepancies or damage to structural members. Approval for modified installation procedures or for major deviation from approved installation procedures shall be obtained from the Regional Supervisor.
(iii) Interim reports shall be submitted by the CVA, as appropriate, to the Regional Supervisor and the lessee.
(iv) A final report shall be prepared by the CVA covering the adequacy of the entire installation phase giving details of how, by whom, and when the independent monitoring activities were conducted and providing any special comments considered necessary. The final report shall describe the CVA's activities during the verification process, summarize the findings, contain a confirmation or denial of compliance with the approved installation plan, and a recommendation to accept or reject the installation. The report shall be submitted to the lessee and, in triplicate, to the Regional Supervisor within 2 weeks of completion of the installation of the platform.
(4) All data provided to the CVA shall be handled in the strictest confidence and not be released by the CVA without the consent of the lessee.
(5) Individuals or organizations acting as CVA's for a particular platform shall not function in any capacity other than that of a CVA for that specific project, whenever the additional activities would create a conflict, or appearance of a conflict of interest.
(b)
(2)
(a)
(1)
(2)
(b)
(2) Short-term and long-term variations of environmental phenomena such as wind, waves, and current shall be described by statistical distributions relevant to the parameter considered. Defensible statistical modeling techniques shall be used in the prediction of extreme values.
(3) When hindcasting techniques are employed to approximate environmental parameters, the validity of the model used shall be defensible.
(c)
(2)
(ii) The design environmental condition shall reflect the various environmental events that individually or collectively represent the most severe conditions the platform is anticipated to experience. Such conditions shall be formulated with a set of parameters that describe the relevant environmental events, including the following:
(A) The maximum wave corresponding to a selected recurrence period together with the associated wind, current, and appropriate ice and snow effects;
(B) The minimum air and sea temperatures appropriate to the event being treated; and
(C) The maximum water level due to tide and storm surge.
(iii) Consideration shall be given to other combinations of the parameters specified in paragraph (c)(2)(ii)(A) of this section involving either maximum wind, maximum current, or maximum ice load which may cause a greater response of the platform.
(iv) In general, the recurrence period chosen for the events specified in paragraphs (c)(2)(ii) (A) and (C) of this section shall primarily be based on the design service life of the platform. For platforms designed for a service life of 20 years, the recurrence period chosen for the determination of these events shall not be less than 100 years. For other service lives, the design event recurrence interval shall generally be adjusted to provide for a risk of occurrence which does not exceed the risk of occurrence for the 20-year/100-year combination.
(v) For installation sites located in seismically active areas, see paragraph (d)(8) of this section.
(3)
(d)
(i) Wave conditions considered for design shall be described by defensible statistical and/or deterministic methods.
(ii) Parameters characterizing design environmental waves shall be based on wave statistics or the results of defensible analytic prediction methods such as hindcasting techniques.
(iii) When using probabilistic analyses, the probability of occurrence of various wave-height groups classified by directionality and for a wide range of possible periods (i.e., tables of exceedance) shall be determined. Where required by the method selected to predict extreme values, the average duration of various wave-height groups (i.e., persistence data) shall be determined. All extrapolations and long-
(iv) When using deterministic methods, waves shall be described by the parameters, height, period, and other relevant shape characteristics. The design-wave formulation used shall be valid for the problem considered.
(v) Breaking-wave criteria appropriate to the installation site shall be determined using defensible formulations.
(vi) If spectral wave data are established for the dynamic analysis of structural response to waves, such data shall be derived in accordance with defensible methods. If spectral data are not available in adequate quantities for the intended application, defensible mathematical formulations that best fit the available data shall be used.
(2) Wind information including the following:
(i) Wind velocities shall be classified on the basis of their duration. Wind velocities having a duration of less than 1 minute are referred to as gust winds. Wind velocities having a duration equal to or greater than 1 minute are referred to as sustained winds. The reference elevation is 33 feet above still-water level.
(ii) Wind conditions considered for design shall be described by defensible statistical or deterministic methods.
(iii) Wind profiles shall be determined on the basis of defensible statistical or mathematical models. Corrections of wind velocity data to averaging periods other than those employed in the collections of data shall be based on defensible methods.
(iv) Distribution of the direction and speed of wind approach to the platform shall be determined, or alternatively, winds shall be considered to approach from any direction.
(3) Current information including the following:
(i) Current velocities to be used in design shall be determined on the basis of the best statistics available. Tidal current, wind-generated current, density current, circulation current, and river-outflow current shall be combined on the basis of their probability of simultaneous occurrence in arriving at current velocities to be used in design.
(ii) Current velocity profiles shall be determined on the basis of site-specific studies or defensible empirical relationships. Unusual profiles due to bottom currents and stratified effects in regions near the mouth of large rivers shall be accounted for.
(iii) Directional data on currents which exist in the absence of waves shall be described for each month or by season. Unless a detailed study of current directions is made, currents shall be assumed to run in any direction.
(4) Tide information including the following:
(i) The design storm-tide elevation shall be identified for the installation site. For design purposes, the design environmental wave height shall be superimposed on the storm-tide elevation.
(ii) Variations in the elevation of the daily lunar tide shall be used in determining the elevations of boat landings, barge fenders, and the corrosion-prevention treatment of platforms in the splash zone (see § 250.906(c)(5) of this part).
(iii) The assumed maximum or storm tide shall include astronomical tide, wind tide, and pressure-induced storm surge. Minimum-tide estimates shall be based on either the astronomical or lunar tide only. The water depth shall be referenced to a datum (e.g., mean low/water or mean low low/water) consistent with all other references to elevations and depths.
(iv) If data directly applicable to the installation site are not available, the best estimate based on data for nearby locations shall be used.
(5) Temperature information including the following:
(i) Extreme values of low temperatures shall be expressed in terms of the most probable, lowest values with their corresponding recurrence periods;
(ii) Air, sea surface, and seabed temperatures shall be accounted for in describing the environment and in justifying the temperatures used in design.
(6) Snow and ice information including the following:
(i) If the platform is to be located in an area where sea ice may develop or drift, ice conditions shall be accounted
(ii)(A) Relevant statistical and physical data on the sea-ice and snow conditions shall be described with particular attention to the following:
(
(
(
(
(
(
(B) The weight of the maximum snow and ice anticipated to accumulate on the platform shall be determined.
(7) Marine growth information including the following:
(i) When assessing the potential for marine growth, account shall be taken of relevant observations and experience in the area. In the absence of such information, defensible analytical techniques shall be employed to assess the potential for marine growth. These techniques shall take into account salinity, oxygen content, hydrogen-ion concentration value, current, temperature, water turbidity, and other appropriate factors.
(ii) Consideration shall be given to the selection of surface coatings which resist breakdown by micro-organisms which reduce the onset of corrosion.
(iii) Particular attention shall be paid to the effects that marine growth has on surface roughness characteristics of submerged structural members.
(8) Earthquake information including the following:
(i) The effects of earthquakes on platforms located in areas known to be seismically active shall be addressed.
(ii) Except for the provision of § 250.905(d)(5)(ii) of this part, the seismicity of the site shall be determined. Preferably, this shall be based on site-specific data. However, regional data shall be deemed acceptable for use when site-specific data are not available and the regional data are interpreted in a manner to produce the most adverse effect on a platform at the specific site. The following data shall be obtained:
(A) Recurrence interval of seismic events appropriate to the design life of the structure,
(B) Proximity to active faults,
(C) Type of faulting,
(D) Attenuation of ground motion between the faults and the site,
(E) Subsurface soil conditions, and
(F) Records from past seismic events at the site or from analogous sites.
(iii) The use of available data to describe the seismic characteristics of the site is permitted where it can be shown that such data are consistent with the requirements of paragraph (d)(8)(ii) of this section.
(iv) The seismic data shall be used to establish a quantitative design earthquake criterion describing the design earthquake-induced ground motion. In addition to ground motion and as applicable to the installation site, the following earthquake-related phenomena shall be taken into account:
(A) Liquefaction of subsurface soils,
(B) Submarine slides,
(C) Tsunamis, and
(D) Fluid motions in tanks.
(a)
(b)
(2) Where applicable, the effects of increased dimensions and weight due to
(c)
(i) Weight in the air of the platform (refer to paragraphs (e)(1) and (f)(1) of this section for itemizations of weight for pilefounded platforms and gravity platforms, respectively).
(ii) Weight of permanent ballast and the weight of permanent machinery including liquids at operating levels.
(iii) External hydrostatic pressure and buoyancy in calm sea conditions calculated on the basis of the design waterline.
(iv) Static earth pressure.
(2)
(i) Weight of drilling and production equipment that can be removed such as derrick, draw works, mud pumps, mud tanks, separators, and tanks.
(ii) Weight of crew and consumable supplies such as mud, chemicals, water, fuel, pipe, cable, stores, drill stem, and casing.
(iii) Weight of liquids in storage tanks.
(iv) Forces exerted on the platform due to drilling, e.g., the maximum derrick reaction when placing or pulling casing.
(v) The forces exerted on the platform during the operation of cranes and vehicles.
(vi) The forces exerted on the platform by vessels moored to the platform.
(vii) The forces exerted on the platform by helicopters during takeoff and landing or while parked on the platform. When applicable, the dynamic effects on the platform of the forces specified in paragraphs (c)(2) (iv) through (vii) of this section shall be taken into account. Live loads occurring during transportation and installation shall be determined for each specific operation involved, and the dynamic effects of such loads shall be addressed (see § 250.910 of this part).
(3)
(4)
(i) Extreme impact loads caused by supply boats, barges, and other craft anticipated to work in the vicinity of the platform;
(ii) Impact loads caused by dropped objects, such as drill collars, casing, blowout-preventer stacks;
(iii) Loss of internal pressure required to resist hydrostatic loading and to maintain buoyancy during the installation of the platform;
(iv) Explosion;
(v) Effects of fire; and
(vi) Iceberg collision.
(5) Environmental load information including the following:
(i) Environmental loads are loads due to wind, waves, current, ice, snow, earthquake, and other environmental phenomena.
(ii) The characteristic parameters defining an environmental load shall be appropriate to the installation site as determined by the studies required by § 250.904 of this part. Operating environmental loads are loads derived from the parameters characterizing operating environmental conditions (see § 250.904(c)(3) of this part). Design environmental loads are loads derived from the parameters characterizing the design environmental condition (see § 250.904(c)(2) of this part).
(iii) Environmental loads shall be applied to the platform from directions producing the most unfavorable effects on the platform unless site-specific studies allow for a less stringent requirement.
(iv) The combination and severity of design environmental loads shall be consistent with the likelihood of their simultaneous occurrence. The simultaneous occurrence of environmental loads shall be modeled by appropriate superposition methods.
(v) Earthquake loads and loads resulting from accidental or rare environmental phenomena need not be combined with other environmental loads unless site-specific conditions indicate that such combination is appropriate.
(d)
(i) Wave-induced loads shall be calculated using defensible methods or shall be obtained from adequate model or field test data;
(ii) A sufficient range of waves and wavecrest positions relative to the platform shall be investigated to ensure an accurate determination of the maximum wave load on the platform;
(iii) Wave impact loads on structural members below the design wave crest elevation shall be accounted for by defensible theoretical methods or relevant model test of full-scale data;
(iv) Where applicable, the possibility of dynamic excitation of the platform due to flow-induced cyclic loading shall be addressed;
(v) For additional requirements pertaining to steel-piled platforms and concrete gravity-platforms, see paragraphs (e)(3) and (f)(3) of this section, respectively; and
(vi) Where applicable, additional hydrostatic loading effects shall be addressed.
(2) Wind load information including the following:
(i) Wind loads, local wind pressures, and wind profiles shall be determined on the basis of defensible analytical methods or wind tunnel tests on a representative model of the platform,
(ii) In determining design environmental loads on the overall platform, wind loads calculated on the basis of the design-sustained wind velocity shall be combined with other design environmental loads,
(iii) The design gust wind load shall be used in the design of local structure unless the effects of the load combination described in paragraph (d)(2)(ii) of this section are more severe,
(iv) Where appropriate, the dynamic effects due to the cyclic nature of gust wind and cyclic loads due to vortex shedding shall be taken into account. Both the drag and lift components of loads due to vortex shedding shall be taken into account.
(v) Where appropriate, flutter and load amplification due to vortex shedding shall be addressed.
(3) Current load information including the following:
(i) Current-induced loads on immersed members of the platform shall be accounted for by defensible methods or the results of model test or site-specific data,
(ii) The lift and drag coefficients used in the determination of current loads shall be appropriate to the current velocity and structural configuration,
(iii) Current velocity profiles used in design shall be appropriate to the installation site,
(iv) For determination of loads induced by the simultaneous occurrence of wave and current fields, the total velocity field shall be computed by defensible methods before computing the total force, and
(v) Where appropriate, flutter and load amplification due to vortex shedding shall be addressed.
(4) Ice and snow load information including the following:
(i) For platforms located in areas associated with ice movement, contact loads caused by floating ice shall be determined according to defensible theoretical methods, model test data, or full-scale measurements;
(ii) In locations where platforms are subject to ice and snow accumulation, the additional weight of snow and ice on the platform shall be addressed;
(iii) The effects of ice accumulation and ice jam, including the effects of changes in configuration due to adhesion, shall be accounted for in the determination of the total environmental load; and
(iv) The incident pressure due to pack ice, pressure ridges, and where appropriate, ice island fragments impinging on the platform shall be addressed.
(5) Earthquake load information including the following:
(i) For platforms located in seismically active areas, design earthquake-induced ground motions shall be determined on the basis of seismic data applicable to the installation site. Design earthquake ground motions shall be described by either applicable ground motion records or response spectra consistent with the recurrence period appropriate to the design life of the platform.
(ii) Available and defensible standardized spectra applicable to the region of the installation site are acceptable if such spectra reflect those site-specific conditions affecting frequency content and energy distribution. These conditions include the type of active faults in the region, the proximity of the site to the potential source faults, the attenuation or amplification of ground motion between the faults and the site, and the soil conditions at the site.
(iii) Ground-motion descriptions shall consist of three components corresponding to two orthogonal horizontal directions and the vertical direction. All three components shall be applied to the platform simultaneously.
(iv)(A) When the response spectrum method is used for structural analysis, input values of ground motion (spectral acceleration representation) shall not be less severe than the following:
(
(
(
(B) The horizontal components shall also be applied in the alternative orthogonal horizontal directions.
(v) If the time history method is used for structural analysis, at least three sets of ground-motion time histories shall be employed. The manner in which the time histories are used shall account for the potential sensitivity of the platform's response to variations in the phasing of the ground-motion records.
(vi) When applicable, effects of soil liquefaction and/or loads resulting from submarine slides or creep, tsunamis, and earthquake motions shall be addressed.
(e)
(1) The dead load of the platform shall include, as appropriate, the weight in air of the jacket, piling, grout, superstructure modules, stiffeners, decking, piping, heliport, and any other fixed structural part less buoyancy, with due allowance for flooding.
(2) Where appropriate, the deformation loads to be accounted for are those resulting from temperature variations leading to thermal stresses in the platform, and those resulting from soil displacements (e.g., differential settlements or lateral displacements).
(3) Wave load information including the following:
(i) For platforms composed of members having diameters that are negligible in relation to the wave lengths considered, semiempirical formulations accounting for wave-induced drag and inertia forces based on the water particle velocities and accelerations on an undisturbed, incident flow field are acceptable;
(ii) When a method as described in paragraph (e)(3)(i) of this section is used, the wave field shall be described by a defensible wave theory appropriate to the wave heights, wave periods, and water depth at the installation site;
(iii) The coefficients of drag and inertia used in calculating wave loads shall be determined on the basis of model test results, published data, or full-scale measurements appropriate to the structural configuration, surface roughness, and wave field; and
(iv) For platforms composed of members whose diameters are not negligible in relation to the wave lengths considered and for structural configurations that will substantially alter the undisturbed, incident flow field, diffraction forces and the hydrodynamic interaction of structural members shall be taken into account.
(f)
(1) The dead load of the platform shall include, as appropriate, the weight in air of the foundation, skirts, columns, superstructure modules, decking, piping, heliport, and any other fixed structural part less buoyancy with due allowance for flooding. Weight calculations based on nominal dimensions and mean values of density are acceptable.
(2) The deformation loads to be accounted for are those due to prestress, shrinkage and expansion, creep, temperature variations, and differential settlements.
(3) Wave load information including the following:
(i) For platforms composed of large gravity bases and one or more columns whose diameters are not negligible in relation to the wave lengths considered, defensible wave-load theories which account for the drag, inertia, and diffraction forces on the platform shall be employed;
(ii) For complex structural configurations, the hydrodynamic interaction of large, immersed structural members shall be addressed;
(iii) When diffraction forces and hydrodynamic interaction are negligible, only semiempirical formulations comparable to those mentioned in paragraphs (e)(3) (i) and (iii) of this section accounting for drag and inertia forces are acceptable; and
(iv) The undisturbed, incident flow field shall be addressed by a defensible wave theory appropriate to the wave heights, wave periods, and water depth at the installation site.
(a)
(b)
(i) Methods of analysis employed in association with the specifications of these requirements shall treat geometric and material nonlinearities in a defensible manner. When nonlinear methods of analysis are used to assess collapse mechanisms, it shall be demonstrated that the platform has sufficient ductility to develop the required resistance or structural displacements.
(ii) Where theoretically based analytical procedures covering the platform or parts thereof are unavailable or not well defined, model studies shall be utilized. The acceptability of model studies depends on the procedures employed, including enumeration of the possible sources of errors, the limits of applicability of the model test results, and the methods of extrapolation to full-scale data.
(2) Loading format information including the following:
(i) Either a deterministic or spectral format shall be employed to describe various load components. When a static approach is used, it shall be demonstrated, where appropriate, that the general effects of dynamic amplification were addressed. The influence of waves other than the highest waves shall be investigated for their potential to produce maximum peak stresses resulting from possible resonance with the platform.
(ii) When considering the design earthquake as discussed in § 250.905 of this part, a dynamic analysis shall be performed. A dynamic analysis shall also be performed to assess the effects of environmental or other types of loads if significant dynamic amplification is expected.
(iii) For fatigue analysis, the long-term distribution of the stress range, with proper consideration of dynamic effects, shall be obtained for relevant loadings anticipated during the design life of the platform (see §§ 250.907(c)(6) and 250.908(c)(6) of this part).
(3) Combinations of loading components information including the following:
(i) Loads imposed during and after installation shall be taken into account. Of the various loads described in § 250.905, of this part, those loads to be considered for design shall be combined in a manner consistent with their probability of simultaneous occurrence. However, earthquake loadings shall be applied without consideration of other
(ii) While it is required to obtain and use those loading components which produce realistic maximum effects on the platform, loading combinations corresponding to conditions after installation shall reflect both operating and design environmental loadings. Sections 250.907, 250.908, and 250.909 of this part give the minimum load combinations to be considered.
(iii) The operating environmental conditions and the maximum tolerable environmental loads during installation shall be specified.
(c)
(2)
(3)
(i) Local vibration due to machinery, equipment, and vortex shedding;
(ii) Stress concentrations at critical joints;
(iii) Secondary stresses induced by large deflections (P-
(iv) Cumulative fatigue;
(v) Corrosion;
(vi) Marine growth; and
(vii) Ice abrasion.
(4)
(i) Equipment and machinery—noise and vibration,
(ii) High-pressure piping—leakage in closed spaces,
(iii) Lifting devices—dropped loads, and
(iv) Vessel mooring devices—line breakage and tripping quick-release mechanisms.
(5)
(i) Submerged zone—that part of the platform below the splash zone,
(ii) Splash zone—that part of the platform between the highest and lowest water levels reached by sea states exceeded for 1 percent of the time annually when superimposed on the highest and lowest levels of tide with due allowance for high and low installation of the platform,
(iii) Atmospheric zone—that part of the platform above the splash zone,
(iv) Ice zone—that part of the platform which can reasonably be expected to come into contact with floating or submerged ice annually.
(a)
(ii) Steels shall exhibit satisfactory formability and weldability characteristics and fracture toughness satisfactory for the intended applications. Materials for structural members which are fracture critical or for members which sustain significant tensile stress and whose fracture would pose a threat to the survival of the platform shall have sufficient toughness to guard against brittle fracture. Materials selected for members which are subjected to significant tensile stress shall have toughness suitable to their intended application.
(iii) In cases where principal loads from either service or weld residual stresses are imposed normal to the plate, appropriate precautions shall be taken to avoid lamellar tearing parallel to the plate surface.
(2) Material selection information including the following:
(i) Steels for structural members shall be selected according to criteria that take into account the required yield strength, fracture toughness, service temperature (see paragraph (a)(3) of this section), and intended application;
(ii) Bolts and nuts shall have mechanical and corrosion properties comparable to the structural elements being joined. Materials for bolts and nuts shall be defined by and tested in accordance with material standards compatible with those for the joined structural members;
(iii) When new alloys are used, the adequacy of fracture toughness shall be supported by appropriate fracture tests; and
(iv) When materials other than steel are used for structural purposes, the mechanical and durability properties necessary for their intended function shall be designated, including toughness and fatigue characteristics, where necessary.
(3)
(i) For material at or below the waterline, the minimum service temperature shall be the lowest average daily water temperature applicable to the particular depth. For material above the waterline, the minimum service temperature shall be the lowest 1-day average daily atmospheric temperature over a 10-year period, unless the material is warmed by auxiliary heating.
(ii) In all cases where material temperature is reduced by localized cryogenic storage or other cooling means, such factors shall be accounted for in establishing minimum service temperature.
(4)
(5)
(b)
(ii) Fabrication other than welding shall be performed in accordance with American Institute of Steel Construction (AISC) publication, Specification for Structural Steel Buildings, Allowable Stress Design and Plastic Design, or other appropriate codes. The code to be followed during fabrication and construction shall be specified on design documents.
(2)
(ii) Forming processes shall not degrade the base metals below their minimum required properties. A heat treatment shall be employed to provide the required properties, where necessary.
(iii) Misalignment between parallel (abutting) members shall be minimized. Weld size for fillet welds shall be sufficient to compensate for the gap
(iv) When arc-air gouging is employed, the carbon buildup and burning of the weld or base metals shall be minimized.
(v) Peening shall not be used for single-pass welds or for the root or cover passes of multipass welds. Peening shall be used only after cleaning of weld passes. Fairing by heating, flame shrinking, or other methods, when applied to Weld Class A or B structural elements, shall be performed without damaging the base metals. Such corrective measures shall be kept to a minimum when treating high-strength steels.
(3)
(i) A suitable system for material identification and quality control during all stages of construction,
(ii) Requirements for welding procedures and welder qualifications,
(iii) The extent of weld inspection (including nondestructive examination methods) and the criteria for weld acceptance or rejection, and
(iv) Necessary dimensional tolerances.
(4)
(ii) As called for in paragraph (b)(3)(iii) of this section, a plan for nondestructive examination of the welds shall be prepared and followed. The extent of inspection of Weld Classes A and B structural elements shall be consistent with the applications involved. Important welds of Weld Classes A and B structural elements are those inaccessible or very difficult to inspect in service. Important welds shall be subjected to an increased level of nondestructive examination during fabrication.
(iii) If the proportion of unacceptable welds becomes excessive, the frequency of nondestructive examination shall be increased.
(c)
(ii) The use of design methods, other than those specifically covered in this section, and their associated safety criteria are allowed if it can be demonstrated that such alternative methods will result in a structural safety level equivalent to that provided by the direct application of these requirements.
(iii) Sections 250.905 and 250.906 of this part shall be consulted regarding definitions and requirements pertinent to the determination of loads and general design requirements.
(2)
(ii) Loadings corresponding to conditions after installation shall include at least those relating to both the operating and design environmental conditions, combined with other pertinent loads in the following manner:
(A) Operating environmental conditions combined with dead and live loads appropriate to the function and operation of the platform;
(B) Design environmental conditions combined with dead and live loads appropriate to the function and operation of the platform;
(C) Design environmental conditions combined with dead loads and minimum live loads appropriate to the function and operation of the platform; and
(iii) For platforms located in seismically active areas, loads induced by
(3)
(ii) Linear, elastic methods (working stress methods) of design and analysis are acceptable if proper measures are taken to prevent general and local buckling failure. Regarding structural instability as a possible mode of failure, the effects of initial stresses and geometric imperfection shall be taken into account.
(iii) Dynamic effects shall be accounted for if the wave energy in the frequency range of the structural resonance frequencies is of sufficient magnitude to produce significant stresses in the platform. The determination of dynamic effects shall be accomplished either by computing the dynamic amplification effects in conjunction with a deterministic analysis or by a random dynamic analysis based on a spectral formulation. In the latter case, the analysis shall be accompanied by a statistical description and evaluation of the relevant input parameters.
(iv) The interaction of the soil with the platform's piles shall be included in the analytical model used to obtain the structural response (see § 250.909(d)(1)(ii) of this part).
(v) For static loads, plastic methods of design and analysis shall be employed only when the properties of the steel and the connections exclude the possibility of brittle fracture and allow for formation of plastic hinges with sufficient plastic rotation capacity and adequate fatigue resistance.
(vi) Whenever plastic analysis is used, it shall be demonstrated that the collapse mode (mechanism) corresponding to the smallest loading intensities has been used for the determination of the ultimate strength of the platform. The effect of buckling and other destabilizing nonlinear effects shall be taken into account in the plastic analysis of platforms with compressive forces. Whenever nonmonotonic or repeating loads are present, it shall be demonstrated that the structure will not fail by incremental collapse or fatigue.
(vii) Under dynamic loads when plastic strains may occur, the considerations specified in paragraph (c)(3)(v) of this section shall be satisfied and any buckling and destabilizing nonlinear effects shall be taken into account.
(4)
(ii) For structural members and loadings covered by AISC publication, Specification for Structural Steel Buildings, Allowable Stress Design and Plastic Design, with the exception of earthquake loadings (see paragraph (c)(4)(v) of this section) and tubular structural members under the combined loading of axial compression and bending, the basic allowable stresses of the members shall be obtained using the AISC specification. For tubular members subjected to the aforementioned interaction, stress limits shall be set in accordance with a defensible formulation.
(iii) Where stresses in members listed in paragraph (c)(4)(ii) of this section are shown to result from forces imposed by the design environmental conditions acting alone or in combination with dead and live loads (see paragraph (c)(2)(ii) of this section), the basic allowable stresses cited in paragraph (c)(4)(ii) of this section, modified by a factor of four-thirds, are permitted for the design environmental load contribution if the resulting structural member sizes are not less than those required for dead and live loads plus operating environmental conditions without the one-third increase in allowable stresses.
(iv) For any two- or three-dimensional stress fields within the scope of the working-stress formulation, the equivalent stress (e.g., the von Mises stress intensity) shall be limited by an
(v) When considering loading combinations on individual members or on the overall platform, which include loads defined as accidental (see § 250.905(c)(4) of this part), or in pursuing structural analysis for earthquake loads (see paragraph (c)(2)(iii) of this section), the allowable stress set at a level of the minimum yield or buckling strength of the material shall be considered appropriate.
(vi) Whenever elastic instability, overall or local, may occur before the compressive stresses reach the minimum specified yield strength of the material, appropriate allowable buckling stresses shall govern.
(vii) Whenever the ultimate strength of the platform is used as the basis for the design of its members, the safety factors or the factored loads shall be formulated in accordance with the requirements of AISC publication, Specification for Structural Steel Buildings, Allowable Stress Design and Plastic Design, or an equivalent code. The capability of the primary structural members to develop their predicted ultimate load capacity shall be demonstrated.
(viii) For details of high-stress concentration, consideration shall be given to safety against brittle fracture and to material quailty-control procedures.
(5)
(ii) The adequacy of structural strength shall be demonstrated by analysis to verify that no significant structural damage occurs; and
(iii) Platforms shall also possess adequate ductility to withstand a rare intense earthquake.
(6)
(ii) For structural members and joints which require a detailed analysis of cumulative fatigue damage, the results of the analysis shall indicate a minimum calculated life of twice the design life (see § 250.906(c)(1) of this part) of the platform if there is sufficient structural redundancy to prevent catastrophic failure of the platform as a result of fatigue failure of the member or joint under consideration. If such redundancy does not exist or if the desirable degree of redundancy is significantly reduced as a result of fatigue damages, the results of a fatigue analysis shall indicate a minimum calculated life of three times the design life of the platform.
(d)
(e)
(a)
(2) Materials, structural systems, methods of design, and methods of construction that do not conform to the requirements of this section shall not be used unless it is shown that they will result in a safety level at least equivalent to that provided by the direct application of the requirements of this section.
(b)
(2)
(ii) The tricalcium aluminate content of the cement shall be such as to enhance the corrosion protection of reinforcing steel without impairing the durability of concrete.
(iii) If oil storage is planned and the oil is expected to contain soluble sulfates in amounts that may impair the durability of concrete, the tricalcium content shall be reduced or a suitable coating employed to protect the concrete.
(3)
(ii) If nonpotable water is used, the proportions of materials in the concrete shall be based on test concrete mixes using water from the same source. The strength of mortar test cubes made with nonpotable water shall not be significantly below the strength of similar cubes made with potable water.
(iii) Water for reinforced or prestressed concrete or grout shall not contain chlorides and sulfates in amounts detrimental to the durability of the platform.
(4)
(ii) Marine aggregates shall be washed with fresh water before use to remove the surface and soluble chlorides and sulfates so that the total chloride and sulfate content of the concrete mix water does not exceed the limits of paragraph (b)(3)(iii) of this section.
(iii) The maximum size of the aggregate shall be such that the concrete can be placed without voids.
(5)
(6)
(ii) Structural steel used in composite structures shall conform to the requirements of § 250.907 of this part.
(7)
(8)
(ii) The maximum allowable contents of chlorides and sulfates determined in accordance with paragraph (b)(3)(iii) of this section shall also apply to grout mixes.
(9)
(10)
(c)
(A) Loss of overall equilibrium,
(B) Failure of critical sections, and
(C) Instability (buckling).
(ii) Additionally, the following items shall be considered in relation to their potential influences on the platform:
(A) Cracking or spalling,
(B) Deformations,
(C) Corrosion of reinforcement or deterioration of concrete, and
(D) Vibrations.
(2)
(3)
(4)
(ii) Crack control design shall be achieved by limiting the crack width in concrete subjected to tension or by limiting the tensile stress in reinforcing steel and prestressing tendons.
(5)
(ii) The following items shall be considered in the four zones of exposure (see § 250.906(c)(5) of this part):
(A) Submerged zone—chemical deterioration of the concrete, corrosion of the reinforcement and hardware, and abrasion of the concrete;
(B) Splash zone—freeze-thaw durability, corrosion of the reinforcement and hardware, the chemical deterioration of the concrete, and fire hazards;
(C) Atmospheric zone—freeze-thaw durability, corrosion of reinforcement and hardware, and fire hazards; and
(D) Ice zone—mechanical deterioration resulting from the abrasive action of moving ice.
(6)
(d)
(ii) The inelastic behavior of concrete, based on the true variation of the modulus of elasticity with stress, shall be taken into account whenever its effect reduces the strength of the platform.
(iii) The geometric nonlinearities and the effect of initial deviation of the platform from the design geometry shall be taken into account whenever their effects reduce the strength of the platform.
(iv) Where appropriate, dynamic effects shall be taken into account. The dynamic response shall be determined by a defensible method that includes the effects of the foundation—platform interaction and the effective mass of the surrounding water.
(v) The material properties used in the analysis shall be based on actual laboratory tests or shall follow the appropriate sections of ACI 318.
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10)
(11)
(12)
(e)
(ii) At each stage of construction, i.e., fabrication, initial flotation, towing, and installation in situ, the forces acting on the platform shall be kept within the safety limits listed in paragraph (c) of this section. Appropriate static and/or dynamic analysis shall be performed for the operating loading conditions of each of the construction operations mentioned above. Buoyancy and stability shall be considered during all phases of construction.
(2)
(ii) When concreting in cold weather, the temperature of the fresh concrete shall be maintained sufficiently above
(iii) In hot weather, the temperature of the fresh concrete shall be controlled so that it does not impair attainment of the desired strength and durability;
(iv) The methods for curing concrete shall ensure maximum compressive and tensile strength, durability, and a minimum of cracking; and
(v) The location and workmanship of construction joints shall not impair the strength, crack resistance, and watertightness of the platform.
(3)
(ii) The welding of reinforcement shall conform to the requirements of AWS publication, AWS D1.4, Structural Welding Code— Reinforcing Steel.
(4)
(ii) Tendons and ducts shall be in a condition that ensures the required strength, durability, and bond.
(iii) The grouting procedures shall produce the required bond strength of the tendons and provide permanent corrosion protection for the tendons. Anchorages shall also be protected adequately against corrosion.
(a)
(2)
(ii) For cases where the limits of applicability of any method of calculation employed are not well defined or where the soil characteristics are quite variable, the use of more than one method of calculation or a parametric study of the sensitivity of the important design variables shall be considered, and
(iii) A listing of design parameters, necessary calculations, and test results shall be retained by the designer.
(b)
(A) Shallow hazards (see paragraph (b)(2) of this section) to obtain relevant geophysical data.
(B) Geological survey (see paragraph (b)(3) of this section) to obtain data of a regional nature concerning the site.
(C) Subsurface investigation and testing (see paragraph (b)(4) of this section) to obtain the necessary geotechnical data. The results of these investigations shall be the basis for the additional site related studies specified in paragraph (b)(5) of this section.
(ii) A complete site-investigation program shall be furnished for each platform. The positioning devices used on the vessel employed in the site investigation as well as those used during the installation of the platform shall have sufficient accuracy to ensure that the data obtained are pertinent to the actual final location of the platform.
(2)
(ii) The information to be obtained from this survey shall include the following items, as appropriate, for the planned platform:
(A) Contours of the sea bed,
(B) Presence of any seafloor surface or near-surface anomaly or obstructions which would adversely affect platform installation at the site,
(C) Shallow faults,
(D) Gas seeps,
(E) Slump blocks,
(F) Occurrence of shallow gas, and
(G) Ice scour of seafloor sediments.
(3)
(ii) Where necessary, the seismic activity at the site shall be assessed. Fault zones, the extent and geometry of faulting, and attenuation effects of conditions in the vicinity of the site shall be identified.
(iii) For platforms located in a producing area, the possibility of seafloor subsidence shall be considered.
(4)
(ii) The subsurface investigation and soil testing program shall consist of adequate in situ testing, boring, and sampling to examine all important soil and rock strata. The testing program shall reveal the necessary strength, classification, and deformation properties of the soil. Further tests, as needed, shall describe the dynamic characteristics of the soil.
(iii) At least one borehole having a minimum depth of the anticipated length of the pile plus a zone of influence shall be drilled at the installation site for a pile-supported platform. Previously gathered borehole data may be used on a case-by-case basis, when approved by the Regional Supervisor. The zone of influence shall be sufficient to ensure that punch through failures will not occur. Additional boreholes of a lesser depth shall be required by the Regional Supervisor if discontinuities in the soil are indicated to exist in the area of the platform.
(iv) For a gravity-type platform foundation, the required depth of the borehole shall be equal to at least the depth of the zone of influence which the structure imposes on the supporting soil. Where possible, in situ tests shall be performed to a depth that will include the anticipated shearing failure zone.
(v) When samples from the field are sent to a laboratory for further testing, they shall be packed carefully and accurately labeled, and the results of visual inspections shall be recorded.
(vi) A summary report showing the results of the soil testing program shall be prepared. The report shall describe briefly the various field and laboratory test methods employed and shall indicate the applicability of these methods as they relate to the quality of the sample, the type of soil, and the anticipated design application.
(vii) The engineering properties of the soil to be used in the design shall be listed for each stratum. The selected design properties shall specify the uncertainties inherent in the overall testing program and in the reliability and applicability of the individual test methods.
(5)
(i) Scouring potential of the seafloor,
(ii) Hydraulic instability and the occurrence of sand waves,
(iii) Instability of slopes in the area where the platform is to be placed,
(iv) Liquefaction and/or possible reduction of soil strength due to increased pore pressures, and
(v) Degradation of subsea permafrost layers.
(c)
(ii) Foundation displacements shall be evaluated to ensure that they are
(iii) The soil and the platform shall be considered as an interactive system, and the results of the analysis as required in paragraphs (c)(2) through (c)(6) of this section shall be evaluated from this point of view.
(2)
(3)
(ii) If scour is not accounted for in design, either effective protection shall be furnished soon after the installation of the platform or frequent visual inspection shall be carried out, particularly after major storms.
(4)
(ii) Maximum allowable values of platform movements, as limited by these structural considerations or overall platform stability, shall be considered in the design.
(5)
(ii) The evaluation of the dynamic response of the platform shall account for, as appropriate, the nonlinear and inelastic characteristics of the soil, the possible deterioration of strength, the increased or decreased damping due to cyclic soil loading, and the influence of nearby platforms.
(6)
(ii) In-place platform loadings to be checked shall include at least those relating to both the operating and design environmental conditions, combined in accordance with the following:
(A) Operating environmental conditions with dead and live loads appropriate to the function and operation of the platform,
(B) Design environmental conditions with dead and live loads appropriate to the function and operation of the platform, and
(C) Design environmental conditions with dead and minimum live loads appropriate to the function and operation of the platform.
(d)
(i) In the design of individual piles and piles in a group, the effects of axial, bending, and lateral loads shall be addressed.
(ii) The design of a pile shall reflect the interactive behavior between the soil and the pile, between the pile and the platform, and between piles in a group.
(iii) Methods of pile installation shall be consistent with the type of soil at the site and the installation equipment available. If unexpectedly high-driving resistance or other conditions lead to a failure of the pile to reach the desired penetration, the pile's capacities shall be reevaluated by considering the actual installation situation.
(iv) Pile driving shall be performed and supervised by qualified and experienced personnel. Driving records which include such information as blowcounts and estimated hammer performance and stoppages shall be retained.
(v) Where necessary, the effects of bottom instability in the vicinity of the platform shall be assessed.
(2)
(ii) The results of the dynamic pile driving analysis alone shall not be used to predict the axial load capacity of a pile.
(iii) For piles driven through clay, the estimated skin friction developed over any increment of the pile surface shall not exceed the shear strength of the clay.
(iv) The capacity of the internal plug of an open-ended pile shall be considered since it may limit the estimated end bearing to the pile.
(v) When combining side friction and end-bearing effects in determining axial pile capacity, the load deflection response of the soil-pile system shall be addressed.
(vi) For piles subjected to pullout loads, the contribution of the end resistance of the pile to its axial capacity shall not be considered. The possible variation of predicted pile-skin friction between the compressive and tensile modes of the axial-pile loading shall be considered.
(3)
(ii) The representation of the soil's lateral displacement when it is subjected to lateral loads shall adequately reflect the deterioration of the lateral load capacity when the soil is subjected to cyclic loading.
(iii) The description of the lateral load versus displacement characteristics for the various soil strata shall be based on constitutive data obtained from suitable soil tests. The use of empirical methods to provide the description of the soil's lateral response shall be permitted if such methods are documented.
(iv) Where applicable, the rapidly deteriorating cyclic lateral load capacity of stiff clays, especially those exhibiting the presence of a secondary structure, shall be addressed in the design.
(v) Calculation of pile deflection and stress induced by lateral loads shall account for the nonlinear interaction between the soil and the pile.
(4)
(5)
(e)
(i) The influence of hydraulic and slope instability, if any, shall be determined for the structural loading cases that include the design environmental loading.
(ii) The effects of adjacent platforms and the variation of soil properties in the horizontal direction shall be considered, as appropriate.
(iii) The stability of the foundation with regard to bearing and sliding failure modes shall be investigated by employing the soil shear strengths determined with consideration of paragraphs (b)(4) and (c)(2) of this section.
(iv) When an underpressure or overpressure is experienced by the seafloor under the platform, provisions shall be made to prevent piping that could impair the integrity of the foundation.
(v) Initial, consolidation, and secondary settlements, as well as permanent horizontal displacements, shall be determined.
(vi) If the intended site is not level, the predicted tilt of the overall platform shall be based on the average bottom slope of the seafloor and the tolerance of the measuring device used in the site-investigation program. Differential settlement shall also be calculated and the tilting of the platform
(2)
(ii) The lateral resistance of the platform shall be investigated considering various potential shearing planes. The presence of any soft layers shall require special consideration.
(iii) Calculations for overturning moment and vertical forces induced by the passage of a wave shall include the vertical pressure distribution across the top of the foundation and along the seafloor. The foundation shall not lose contact with the soil due to uplift created by the maximum overturning moment.
(iv) The capacity of the foundation to resist a deep-seated bearing failure shall be analyzed.
(v) Where present, the additional effects of penetrating walls or skirts that transfer vertical and lateral loads to the soil shall be investigated for their contribution to bearing load capacity and lateral resistance.
(3)
(ii) The distribution of soil reactions shall be based on the results obtained in paragraphs (b)(2) and (b)(4) of this section, and the calculations of soil reactions shall account for any deviation from a plane surface, the load-deflection characteristics of the soil, and the geometry of the platform base.
(iii) Where applicable, effects of local soil stiffening, nonhomogeneous soil properties, and boulders and other obstructions shall be addressed in the design. During installation, the possibility of local contact pressures due to irregular contact between the base and the seafloor shall be considered. Contact pressures shall be added to the hydrostatic pressure.
(iv) The penetration resistance of structural elements projecting into the seafloor below the foundation structure shall be analyzed. The design of the ballasting system shall reflect uncertainties associated with achieving the required penetration of the platform.
(a)
(i) Lifting and mooring,
(ii) Loadout or initial flotation,
(iii) Fabrication afloat,
(iv) Towing,
(v) Launching and uprighting,
(vi) Submergence,
(vii) Pile installation, and
(viii) Final field erection.
(2) The requirements of this section apply to all platforms covered by this subpart, regardless of structural type or material of construction.
(b)
(c)
(2) Analyses shall be performed to ensure that the structural design is sufficient to withstand the type and magnitude of the loads and load combinations determined, in accordance with paragraph (c)(1) of this section, without loss or degradation of structural integrity.
(3) Analyses shall be performed to ensure that the platform or its means of support has sufficient hydrostatic stability and reserve buoyancy to allow for successful execution of all phases of marine operations.
(a)
(2)
(3)
(4)
(b)
(i) Material quality and forming,
(ii) Welder and welding procedure qualifications,
(iii) Weld inspection,
(iv) Tolerances and alignments, and
(v) Corrosion-control systems.
(2)
(3)
(ii) All welding procedures to be employed shall be tested and certified for the production of satisfactory welds. Welding procedures previously tested and certified shall be considered prequalified.
(4)
(ii) The extent and methods of inspection shall be consistent with the classification of applications (see § 250.907(a)(4) of this part) of the area being examined.
(iii) Any welding not meeting the acceptance criteria specified in the inspection plan shall be rejected and appropriate remedial action taken.
(5)
(6)
(7)
(ii) The construction site shall be inspected to ensure that adequate consideration has been given to the following items:
(A) Support of the platform during construction,
(B) Employment of a sufficient number of certified welders and inspectors to maintain an adequate quality of work, and
(C) Weathertight storage of welding consumables under conditions specified by their manufacturers.
(iii) Inspection shall verify that the following operations have been accomplished in a manner conforming to approved plans or drawings:
(A) Loadout,
(B) Tie down,
(C) Positioning at the site,
(D) Installation (see § 250.909(d)(1)(iv) of this part for piles), and
(E) Final field erection.
(iv) To determine if overstressing of the platform during transportation has occurred, towing records shall be reviewed to ascertain if conditions during towing operations exceeded those employed in the analyses required by § 250.910(c) of this part.
(v) When the inspections indicate that overstressing has occurred during loadout, transportation, or installation, the affected parts of the platform shall be surveyed to determine the extent of actual damage, if any. Where necessary, a reevaluation of the structural capacity shall be carried out, considering the results of the survey.
(8)
(i) Mill certificates,
(ii) Weld-procedure qualification records,
(iii) Weld inspection records,
(iv) Dimensional tolerance reports,
(v) Towing records, and
(vi) Pile driving records.
(c)
(i) Preparation for concrete production and placement;
(ii) Batching, mixing, and placing concrete;
(iii) Form removal and concrete curing;
(iv) Pretensioning and grouting;
(v) Joints; and
(vi) Finished concrete.
(2)
(ii) Forms and shoring supporting the forms shall be inspected to ensure that they are adequate in number and type and are located correctly.
(iii) The dimensional tolerances of the forms shall be inspected to ensure that the finished dimensional tolerances are comparable to those allowed for in the approved design.
(iv) Reinforcing steel, prestressing tendons, post-tensioning ducts, anchorages, and any other embedded steel shall be inspected, as appropriate, for size, bending, spacing, location, firmness of installation, surface condition, vent locations, proper duct coupling, and duct capping.
(3)
(ii) Inspection shall verify that the mix components of each batch of concrete are properly proportioned and within allowable variations specified in the approved design. Inspection shall ensure that the water/cement ratio of each batch is within the limit specified in § 250.908(b)(7) of this part.
(iii) Aggregate gradation, cleanliness, moisture content, and unit weight shall be tested. The frequency of testing shall be determined taking into account the uniformity of the supply source, volume of concrete used, and variations of atmospheric conditions.
(iv) Mix water shall be tested for purity following specified methods and schedules.
(v) Testing during the production of concrete shall be performed to monitor, as a minimum, the following concrete qualities:
(A) Consistency,
(B) Air content, and
(C) Strength.
(4)
(ii) Inspection shall ensure that curing of concrete is accomplished in accordance with the provisions of a predetermined procedure.
(iii) Where the construction procedures require the submergence of recently placed concrete, inspection shall ensure that methods for protecting the concrete from the effects of salt water are properly executed.
(5)
(ii) Pretensioning or post-tensioning stress shall be determined by measuring both tendon elongation and tendon force. Inspection shall verify that the variation of measurements does not exceed a specified amount.
(iii) Inspection shall verify that grout mix proportions and ambient conditions during mixing are in accordance with provisions designated in the approved design. Tests for grout, viscosity expansion, bleeding, compressive strength, and setting time shall be performed to ensure compliance with design requirements. Procedures shall be observed to ensure that ducts are completely filled.
(iv) Anchorages shall be inspected to ensure that they are located and sized as specified in the design and are provided with adequate cover to mitigate the effects of corrosion.
(6)
(7)
(ii) The platform shall be examined by using a calibrated rebound hammer or a similar nondestructive examination device. Inspection shall verify that the results of surface inspection, cylinder strength test, or nondestructive examination are in accordance with the approved design criteria.
(iii) The completed sections of the platform shall be checked for compliance to specified design tolerances of thickness and alignment and, to the extent practicable, the location of reinforcing and prestressing steel and post-tensioning ducts.
(8)
(ii) Inspection shall ensure that adequate consideration has been given the following items:
(A) Support of the structure during construction,
(B) Employment of a sufficient number of competent workmen and inspectors to maintain an adequate quality of work,
(C) Storage of cement and prestressing tendons in weathertight areas,
(D) Storage of admixtures and epoxies according to manufacturers’ specifications, and
(E) Storage of aggregates to limit segregation, contamination by deleterious substances, and moisture variations within the stockpile.
(iii) Inspection shall verify that the following operations, as applicable to the planned platform, have been accomplished in a manner conforming to approved plans or drawings developed for these operations:
(A) Loadout,
(B) Towing arrangements,
(C) Positioning at the site,
(D) Installation, and
(E) Final field erection.
(iv) To determine if overstressing of the platform during transportation has occurred, towing records shall be reviewed to ascertain if conditions during the towing operations exceeded those employed in the analyses required by § 250.910(c) of this part.
(9)
(i) Material certificates and test reports;
(ii) Tensioning and grouting records;
(iii) Concreting records including weight, moisture content, mix proportions, test methods and results, ambient conditions during the pour, and test equipment calibration data;
(iv) Deviations from design or fabrication specifications and repairs carried out;
(v) Towing records; and
(vi) Data on initial structural settlements.
(a) All platforms installed in the OCS shall be inspected periodically in accordance with the provisions of API RP 2A, section 14, Surveys. However, use of an inspection interval which exceeds 5 years shall require prior approval by the Regional Supervisor. Proper maintenance shall be performed to assure the structural integrity of the platform as a workbase for oil and gas operations.
(b) A report shall be submitted annually on November 1 to the Regional Supervisor stating which platforms have been inspected in the preceding 12 months, the extent and area of inspection, and the type of inspection employed, i.e., visual, magnetic particle, ultrasonic testing. A summary of the testing results shall be submitted indicating what repairs, if any, were needed and the overall structural condition of the platform.
(a) The lessee shall remove all structures in a manner approved by the Regional Supervisor to assure that the location has been cleared of all obstructions to other activities in the area.
(b) All platforms (including casing, wellhead equipment, templates, and piling) shall be removed by the lessee to a depth of at least 15 feet below the ocean floor or to a depth approved by the Regional Supervisor based upon the type of structure or ocean-bottom conditions.
(c) The lessee shall verify by appropriate means that the location has been cleared of all obstructions. The results of the location clearance survey shall be submitted to the Regional Supervisor by means of a letter from the company performing the work certifying that the area was cleared of all obstructions, the date the work was performed, the extent of the area surveyed, and the survey method used.
The lessee shall compile, retain, and make available to Minerals Management Service representatives for the functional life of all platforms, the as-built structural drawings, the design assumptions and analyses, a summary of the nondestructive examination records, and the inspection results from platform inspections required by § 250.912 of this part.
(a) Pipelines and associated valves, flanges, and fittings shall be designed, installed, operated, maintained, and abandoned to provide safe and pollution-free transportation of fluids in a manner which does not unduly interfere with other uses in the Outer Continental Shelf (OCS).
(b) An application shall be submitted to the Regional Supervisor and approval obtained prior to the installation, modification, or abandonment of a pipeline which qualifies as a lease term pipeline (see § 250.1001, Definitions) and prior to the installation of a right-of-way pipeline or the modification or relinquishment of a pipeline right-of-way.
(c)(1) Department of the Interior (DOI) pipelines, as defined in § 250.1001, must meet the requirements in §§ 250.1000 through 250.1008.
(2) A pipeline right-of-way grant holder must identify in writing to the Regional Supervisor the operator of any pipeline located on its right-of-way, if the operator is different from the right-of-way grant holder.
(3) A producing operator must identify for its own records, on all existing pipelines located on its lease or right-of-way, the specific points at which operating responsibility transfers to a transporting operator.
(i) Each producing operator must, if practical, durably mark all of its above-water transfer points by April 14, 1999 or the date a pipeline begins service, whichever is later.
(ii) If it is not practical to durably mark a transfer point, and the transfer point is located above water, then the operator must identify the transfer point on a schematic located on the facility.
(iii) If a transfer point is located below water, then the operator must identify the transfer point on a schematic and provide the schematic to MMS upon request.
(iv) If adjoining producing and transporting operators cannot agree on a transfer point by April 14, 1999, the MMS Regional Supervisor and the Department of Transportation (DOT) Office of Pipeline Safety (OPS) Regional Director may jointly determine the transfer point.
(4) The transfer point serves as a regulatory boundary. An operator may write to the MMS Regional Supervisor to request an exception to this requirement for an individual facility or area. The Regional Supervisor, in consultation with the OPS Regional Director and affected parties, may grant the request.
(5) Pipeline segments designed, constructed, maintained, and operated under DOT regulations but transferring to DOI regulation as of October 16, 1998, may continue to operate under DOT design and construction requirements until significant modifications or repairs are made to those segments. After October 16, 1998, MMS operational and maintenance requirements will apply to those segments.
(d) A pipeline which qualifies as a right-of-way pipeline (see § 250.1001, Definitions) shall not be installed until a right-of-way has been requested and granted in accordance with this subpart.
(e)(1) The Regional Supervisor may suspend any pipeline operation upon a determination by the Regional Supervisor that continued activity would threaten or result in serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, mineral deposits, or the marine, coastal, or human environment.
(2) The Regional Supervisor may also suspend pipeline operations or a right-of-way grant if the Regional Supervisor determines that the lessee or right-of-
(3) The Secretary of the Interior (Secretary) may cancel a pipeline permit or right-of-way grant in accordance with 43 U.S.C. 1334(a)(2). A right-of-way grant may be forfeited in accordance with 43 U.S.C. 1334(e).
Terms used in this subpart shall have the meanings given below:
(a) Are contained within the boundaries of a single lease or group unitized leases but are not owned and operated by the lessee or operator of that lease or unit,
(b) Are contained within the boundaries of contiguous (not cornering) leases which do not have a common lessee or operator,
(c) Are contained within the boundaries of contiguous (not cornering) leases which have a common lessee or operator but are not owned and operated by that common lessee or operator, or
(d) Cross any portion of an unleased block(s).
(a) The internal design pressure for steel pipe shall be determined in accordance with the following formula:
(b)(1) Pipeline valves shall meet the minimum design requirements of American Petroleum Institute (API) Spec 6A, API Spec 6D, or the equivalent. A valve may not be used under operating conditions that exceed the applicable pressure-temperature ratings contained in those standards.
(2) Pipeline flanges and flange accessories shall meet the minimum design requirements of ANSI B16.5, API Spec 6A, or the equivalent. Each flange assembly must be able to withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service.
(3) Pipeline fittings shall have pressure-temperature ratings based on stresses for pipe of the same or equivalent material. The actual bursting
(c) The maximum allowable operating pressure (MAOP) shall not exceed the least of the following:
(1) Internal design pressure of the pipeline, valves, flanges, and fittings;
(2) Eighty percent of the hydrostatic pressure test (HPT) of the pipeline; or
(3) If applicable, the MAOP of the receiving pipeline when the proposed pipeline and the receiving pipeline are connected at a subsea tie-in.
(d) If the maximum source pressure (MSP), exceeds the pipeline's MAOP, redundant safety devices meeting the requirements of section A9 of API RP 14C shall be installed and maintained. Pressure safety valves (PSV) may be used only after a determination by the Regional Supervisor that the pressure will be relieved in a safe and pollution-free manner. The setting level at which the primary and redundant safety equipment actuates shall not exceed the pipeline's MAOP.
(e) Pipelines shall be provided with an external protective coating capable of minimizing underfilm corrosion and a cathodic protection system designed to mitigate corrosion for at least 20 years.
(f) Pipelines shall be designed and maintained to mitigate any reasonably anticipated detrimental effects of water currents, storm or ice scouring, soft bottoms, mud slides, earthquakes, subfreezing temperatures, and other environmental factors.
(a)(1) Pipelines greater than 8-5/8 inches in diameter and installed in water depths of less than 200 feet shall be buried to a depth of at least 3 feet unless they are located in pipeline congested areas or seismically active areas as determined by the Regional Supervisor. Nevertheless, the Regional Supervisor may require burial of any pipeline if the Regional Supervisor determines that such burial will reduce the likelihood of environmental degradation or that the pipeline may constitute a hazard to trawling operations or other uses. A trawl test or diver survey may be required to determine whether or not pipeline burial is necessary or to determine whether a pipeline has been properly buried.
(2) Pipeline valves, taps, tie-ins, capped lines, and repaired sections that could be obstructive shall be provided with at least 3 feet of cover unless the Regional Supervisor determines that such items present no hazard to trawling or other operations. A protective device may be used to cover an obstruction in lieu of burial if it is approved by the Regional Supervisor prior to installation.
(3) Pipelines shall be installed with a minimum separation of 18 inches at pipeline crossings and from obstructions.
(4) Pipeline risers installed after April 1, 1988, shall be protected from physical damage that could result from contact with floating vessels. Riser protection on pipelines installed on or before April 1, 1988, may be required when the Regional Supervisor determines that significant damage potential exists.
(b)(1) Pipelines shall be hydrostatically tested with water at a stabilized pressure of at least 1.25 times the MAOP for at least 8 hours when installed, relocated, uprated, or reactivated after being out-of-service for more than 1 year.
(2) Prior to returning a pipeline to service after a repair, the pipeline shall be pressure tested with water or processed natural gas at a minimum stabilized pressure of at least 1.25 times the MAOP for at least 2 hours.
(3) Pipelines shall not be pressure tested at a pressure which produces a stress in the pipeline in excess of 95 percent of the specified minimum-yield strength of the pipeline. A temperature recorder measuring test fluid temperature synchronized with a pressure recorder along with deadweight test readings shall be employed for all pressure testing. When a pipeline is pressure tested, no observable leakage shall be allowed. Pressure gauges and recorders shall be of sufficient accuracy to verify that leakage is not occurring.
(4) The Regional Supervisor may require pressure testing of pipelines to verify the integrity of the system when the Regional Supervisor determines
(c) When a pipeline is repaired utilizing a clamp, the clamp shall be a full encirclement clamp able to withstand the anticipated pipeline pressure.
(a) The lessee shall ensure the proper installation, operation, and maintenance of safety devices required by this section on all incoming, departing, and crossing pipelines on platforms.
(b)(1)(i) Incoming pipelines to a platform shall be equipped with a flow safety valve (FSV).
(ii) For sulphur operations, incoming pipelines delivering gas to the power plant platform may be equipped with high- and low-pressure sensors (PSHL), which activate audible and visual alarms in lieu of requirements in paragraph (b)(1)(i) of this section. The PSHL shall be set at 15 percent or 5 psi, whichever is greater, above and below the normal operating pressure range.
(2) Incoming pipelines boarding to a production platform shall be equipped with an automatic shutdown valve (SDV) immediately upon boarding the platform. The SDV shall be connected to the automatic- and remote-emergency shut-in systems.
(3) Departing pipelines receiving production from production facilities shall be protected by high- and low-pressure sensors (PSHL) to directly or indirectly shut in all production facilities. The PSHL shall be set not to exceed 15 percent above and below the normal operating pressure range. However, high pilots shall not be set above the pipeline's MAOP.
(4) Crossing pipelines on production or manned nonproduction platforms which do not receive production from the platform shall be equipped with an SDV immediately upon boarding the platform. The SDV shall be operated by a PSHL on the departing pipelines and connected to the platform automatic- and remote-emergency shut-in systems.
(5) The Regional Supervisor may require that oil pipelines be equipped with a metering system to provide a continuous volumetric comparison between the input to the line at the structure(s) and the deliveries onshore. The system shall include an alarm system and shall be of adequate sensitivity to detect variations between input and discharge volumes. In lieu of the foregoing, a system capable of detecting leaks in the pipeline may be substituted with the approval of the Regional Supervisor.
(6) Pipelines incoming to a subsea tie-in shall be equipped with a block valve and an FSV. Bidirectional pipelines connected to a subsea tie-in shall be equipped with only a block valve.
(7) Gas-lift or water-injection pipelines on unmanned platforms need only be equipped with an FSV installed immediately upstream of each casing annulus or the first inlet valve on the christmas tree.
(8) Bidirectional pipelines shall be equipped with a PSHL and an SDV immediately upon boarding each platform.
(9) Pipeline pumps shall comply with Section A7 of API RP 14C. The setting levels for the PSHL devices are specified in paragraph (b)(3) of this section.
(c) If the required safety equipment is rendered ineffective or removed from service on pipelines which are continued in operation, an equivalent degree of safety shall be provided. The safety equipment shall be identified by the placement of a sign on the equipment stating that the equipment is rendered ineffective or removed from service.
(a) Pipeline routes shall be inspected at time intervals and methods prescribed by the Regional Supervisor for indication of pipeline leakage. The results of these inspections shall be retained for at least 2 years and be made available to the Regional Supervisor upon request.
(b) When pipelines are protected by rectifiers or anodes for which the initial life expectancy of the cathodic protection system either cannot be calculated or calculations indicate a life expectancy of less than 20 years, such pipelines shall be inspected annually by taking measurements of pipe-to-electrolyte potential measurements.
(a)(1) A pipeline may be abandoned in place if, in the opinion of the Regional Supervisor, it does not constitute a hazard to navigation, commercial fishing operations, or unduly interfere with other uses in the OCS. Pipelines to be abandoned in place shall be flushed, filled with seawater, cut, and plugged with the ends buried at least 3 feet.
(2) Pipelines abandoned by removal shall be pigged, unless the Regional Supervisor determines that such procedure is not practical, and flushed with water prior to removal.
(b)(1) Pipelines taken out-of-service shall be blind flanged or isolated with a closed block valve at each end.
(2) Pipelines taken out-of-service for a period of more than 1 year shall be flushed and filled with inhibited seawater.
(3) Pipelines taken out-of-service shall be returned to service within 5 years or be abandoned in accordance with the requirements of paragraph (a) (1) or (2) of this section.
(a) Applications to install a lease term pipeline or for a pipeline right-of-way grant must be submitted in quadruplicate to the Regional Supervisor. Right-of-way grant applications must include an identification of the operator of the pipeline. Each application must include the following:
(1) Plat(s) drawn to a scale specified by the Regional Supervisor showing major features and other pertinent data including area, lease, and block designations; water depths; route; length in Federal waters; width of right-of-way, if applicable; connecting facilities; size; product(s) to be transported with anticipated gravity or density; burial depth; direction of flow; X-Y coordinates of key points; and the location of other pipelines that will be connected to or crossed by the proposed pipeline(s). The initial and terminal points of the pipeline and any continuation into State jurisdiction shall be accurately located even if the pipeline is to have an onshore terminal point. A plat(s) submitted for a pipeline right-of-way shall bear a signed certificate upon its face by the engineer who made the map that certifies that the right-of-way is accurately represented upon the map and that the design characteristics of the associated pipeline are in accordance with applicable regulations.
(2) A schematic drawing showing the size, weight, grade, wall thickness, and type of line pipe and risers; pressure-regulating devices (including back-pressure regulators); sensing devices with associated pressure-control lines; PSV's and settings; SDV's, FSV's, and block valves; and manifolds. This schematic drawing shall also show input source(s), e.g., wells, pumps, compressors, and vessels; maximum input pressure(s); the rated working pressure, as specified by ANSI or API, of all valves, flanges, and fittings; the initial receiving equipment and its rated working pressure; and associated safety equipment and pig launchers and receivers. The schematic must indicate the point on the OCS at which operating responsibility transfers between a producing operator and a transporting operator.
(3) General information as follows:
(i) Description of cathodic protection system. If pipeline anodes are to be used, specify the type, size, weight, number, spacing, and anticipated life;
(ii) Description of external pipeline coating system;
(iii) Description of internal protective measures;
(iv) Specific gravity of the empty pipe;
(v) MSP;
(vi) MAOP and calculations used in its determination;
(vii) Hydrostatic test pressure, medium, and period of time that the line will be tested;
(viii) MAOP of the receiving pipeline or facility,
(ix) Proposed date for commencing installation and estimated time for construction; and
(x) Type of protection to be afforded crossing pipelines, subsea valves, taps, and manifold assemblies, if applicable.
(4) The application shall include a description of any additional design precautions which were taken to enable the pipeline to withstand the effects of water currents, storm or ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and other environmental factors.
(5) The application shall include a shallow hazards survey report and, if required by the Regional Director, an archaeological resource report that covers the entire length of the pipeline. A shallow hazards analysis may be included in a lease term pipeline application in lieu of the shallow hazards survey report with the approval of the Regional Director. The Regional Director may require the submission of the data upon which the report or analysis is based.
(b) Applications to modify an approved lease term pipeline or right-of-way grant shall be submitted in quadruplicate to the Regional Supervisor. These applications need only address those items in the original application affected by the proposed modification.
(c) Applications to abandon a lease term pipeline or relinquish a right-of-way grant shall be submitted in triplicate to the Regional Supervisor and shall include the following:
(1) Reason for operation,
(2) Proposed procedures,
(3) “As-built” location plat,
(4) Length in feet of segment to be abandoned or relinquished, and
(5) Length in feet of segment remaining.
(a) The lessee, or right-of-way holder, shall notify the Regional Supervisor at least 48 hours prior to commencing the installation or relocation of a pipeline or conducting a pressure test on a pipeline.
(b) The lessee or right-of-way holder shall submit a report to the Regional Supervisor within 90 days after completion of any pipeline construction. The report, submitted in triplicate, shall include an “as-built” location plat drawn to a scale specified by the Regional Supervisor showing the location, length in Federal waters, and X-Y coordinates of key points; the completion date; the proposed date of first operation; and the HPT data. Pipeline right-of-way “as-built” location plats shall be certified by a registered engineer or land surveyor and show the boundaries of the right-of-way as granted. If there is a substantial deviation of the pipeline route as granted in the right-of-way, the report shall include a discussion of the reasons for such deviation.
(c) The lessee or right-of-way holder shall report to the Regional Supervisor any pipeline taken out of service. If the period of time in which the pipeline is out of service is greater than 60 days, written confirmation is also required.
(d) The lessee or right-of-way holder shall report to the Regional Supervisor when any required pipeline safety equipment is taken out of service for more than 12 hours. The Regional Supervisor shall be notified when the equipment is returned to service.
(e) The lessee or right-of-way holder shall notify the Regional Supervisor prior to the repair of any pipeline or as soon as practicable. A detailed report of the repair of a pipeline or pipeline component shall be submitted to the Regional Supervisor within 30 days after completion of the repairs. The report shall include the following:
(1) Description of repairs,
(2) Results of pressure test, and
(3) Date returned to service.
(f) The Regional Supervisor may require that DOI pipeline failures be analyzed and that samples of a failed section be examined in a laboratory to assist in determining the cause of the failure. A comprehensive written report of the information obtained shall be submitted by the lessee to the Regional Supervisor as soon as available.
(g) If the effects of scouring, soft bottoms, or other environmental factors are observed to be detrimentally affecting a pipeline, a plan of corrective
(h) The results and conclusions of measurements of pipe-to-electrolyte potential measurements taken annually on DOI pipelines in accordance with § 250.1005(b) of this part shall be submitted to the Regional Supervisor by the lessee before March of each year.
(a)(1) In addition to applicable requirements of §§ 250.1000 through 250.1008 and other regulations of this part, regulations of the Department of Transportation, Department of the Army, and the Federal Energy Regulatory Commission (FERC), when a pipeline qualifies as a right-of-way pipeline, the pipeline shall not be installed until a right-of-way has been requested and granted in accordance with this subpart. The right-of-way grant is issued pursuant to 43 U.S.C. 1334(e) and may be acquired and held only by citizens and nationals of the United States; aliens lawfully admitted for permanent residence in the United States as defined in 8 U.S.C. 1101(a)(20); private, public, or municipal corporations organized under the laws of the United States or territory thereof, the District of Columbia, or of any State; or associations of such citizens, nationals, resident aliens, or private, public, or municipal corporations, States, or political subdivisions of States.
(2) A right-of-way shall include the site on which the pipeline and associated structures are to be situated, shall not exceed 200 feet in width unless safety and environmental factors during construction and operation of the associated right-of-way pipeline require a greater width, and shall be limited to the area reasonably necessary for pumping stations or other accessory structures.
(b)(1) When you apply for, or are the holder of, a right-of-way, you must:
(i) Provide and maintain a $300,000 bond (in addition to the bond coverage required in part 256) that guarantees compliance with all the terms and conditions of the rights-of-way you hold in an OCS area; and
(ii) Provide additional security if the Regional Director determines that a bond in excess of $300,000 is needed.
(2) For the purpose of this paragraph, there are three areas:
(i) The areas offshore the Gulf of Mexico and Atlantic Coast;
(ii) The area offshore the Pacific Coast States of California, Oregon, Washington, and Hawaii; and
(iii) The area offshore the Coast of Alaska.
(3) If, as the result of a default, the surety on a right-of-way grant bond makes payment to the Government of any indebtedness under a grant secured by the bond, the face amount of such bond and the surety's liability shall be reduced by the amount of such payment.
(4) After a default, a new bond in the amount of $300,000 shall be posted within 6 months or such shorter period as the Regional Supervisor may direct. Failure to post a new bond shall be grounds for forfeiture of all grants covered by the defaulted bond.
(c) An applicant, by accepting a right-of-way grant, agrees to comply with the following requirements:
(1) The right-of-way holder shall comply with applicable laws and regulations and the terms of the grant.
(2) For the first calendar year, or fraction thereof, and annually thereafter, the right-of-way holder shall pay MMS, in advance, an annual rental of $15 for each statute mile, or fraction thereof, traversed by the right-of-way and $75 for each area to be used as a site for an accessory to the right-of-way pipeline including, but not limited to, a platform. Payments may be on an annual basis, for a 5-year period, or for multiples of 5 years.
(3) The granting of the right-of-way shall be subject to the express condition that the rights granted shall not prevent or interfere in any way with the management, administration, or the granting of other rights by the United States, either prior or subsequent to the granting of the right-of-
(4) If the right-of-way holder discovers any archaeological resource while conducting operations within the right-of-way, the right-of-way holder shall immediately halt operations within the area of the discovery and report the discovery to the Regional Director. If investigations determine that the resource is significant, the Regional Director will inform the lessee how to protect it.
(5) The Regional Supervisor shall be kept informed at all times of the right-of-way holder's address and, if a corporation, the address of its principal place of business and the name and address of the officer or agent authorized to be served with process.
(6) The right-of-way holder shall pay the United States or its lessees or right-of-way holders, as the case may be, the full value of all damages to the property of the United States or its said lessees or right-of-way holders and shall indemnify the United States against any and all liability for damages to life, person, or property arising from the occupation and use of the area covered by the right-of-way grant.
(7)(i) The holder of a right-of-way oil or gas pipeline shall transport or purchase oil or natural gas produced from submerged lands in the vicinity of the pipeline without discrimination and in such proportionate amounts as the FERC may, after a full hearing with due notice thereof to the interested parties, determine to be reasonable, taking into account, among other things, conservation and the prevention of waste.
(ii) Unless otherwise exempted by FERC pursuant to 43 U.S.C. 1334(f)(2), the holder shall—
(A) Provide open and nondiscriminatory access to a right-of-way pipeline to both owner and nonowner shippers, and
(B) Comply with the provisions of 43 U.S.C. 1334(f)(1)(B) under which FERC may order an expansion of the throughput capacity of a right-of-way pipeline which is approved after September 18, 1978, and which is not located in the Gulf of Mexico or the Santa Barbara Channel.
(8) The area covered by a right-of-way and all improvements thereon shall be kept open at all reasonable times for inspection by the Minerals Management Service (MMS). The right-of-way holder shall make available all records relative to the design, construction, operation, maintenance and repair, and investigations on or with regard to such area.
(9) Upon relinquishment, forfeiture, or cancellation of a right-of-way grant, the right-of-way holder shall remove all platforms, structures, domes over valves, pipes, taps, and valves along the right-of-way. All of these improvements shall be removed by the holder within 1 year of the effective date of the relinquishment, forfeiture, or cancellation unless this requirement is waived in writing by the Regional Supervisor. All such improvements not removed within the time provided herein shall become the property of the United States but that shall not relieve the holder of liability for the cost of their removal or for restoration of the site. Furthermore, the holder is responsible for accidents or damages which might occur as a result of failure to timely remove improvements and equipment and restore a site. An application for relinquishment of a right-of-way grant shall be filed in accordance with § 250.1014 of this part.
(d) Failure to comply with the Act, regulations, or any conditions of the right-of-way grant prescribed by the Regional Supervisor shall be grounds for forfeiture of the grant in an appropriate judicial proceeding instituted by the United States in any U.S. District Court having jurisdiction in accordance with the provisions of 43 U.S.C. 1349.
(e) Any right-of-way granted under the provisions of this subpart remains in effect as long as the associated pipeline is properly maintained and used for the purpose for which the grant was
(a) You must submit an original and three copies of an application for a new or modified pipeline right-of-way grant to the Regional Supervisor. The application must address those items required by § 250.1007 (a) or (b) of this subpart, as applicable. It must also state the primary purpose for which you will use the right-of-way grant. If the right-of-way has been used before the application is made, the application must state the date such use began, by whom, and the date the applicant obtained control of the improvement. When you file your application, you must pay the rental required under § 250.1009(c)(2) of this subpart and a non-refundable filing fee of $2,350 for a pipeline right-of-way grant to install a new pipeline or a non-refundable filing fee of $300 for a pipeline right-of-way grant to convert an existing lease term pipeline into a right-of-way pipe- line. MMS periodically will amend the filing fee based on its experience with the costs for administering pipeline right-of-way applications. If the costs change by a percentage of not more than the percentage change in the CPI “U” since the last change to the filing fee, MMS will amend the application fee by the percentage of the change in costs without notice and opportunity for comment. If costs increase by a percentage more than the percentage change in the CPI “U” since the last change to the filing fee, MMS will provide notice and an opportunity to comment before it changes the filing fee. An application to modify an approved right-of-way grant shall be accompanied by the additional rental required under § 250.1009(c)(2), if applicable. A separate application shall be filed for each right-of-way.
(b)(1) An individual applicant shall submit a statement of citizenship or nationality with the application. An applicant who is an alien lawfully admitted for permanent residence in the United States shall also submit evidence of such status with the application.
(2) If the applicant is an association (including a partnership), the application shall also be accompanied by a certified copy of the articles of association or appropriate reference to a copy of such articles already filed with MMS and a statement as to any subsequent amendments.
(3) If the applicant is a corporation, the application shall also include the following:
(i) A statement certified by the Secretary or Assistant Secretary of the corporation with the corporate seal showing the State in which it is incorporated and the name of the person(s) authorized to act on behalf of the corporation, or
(ii) In lieu of such a statement, an appropriate reference to statements or records previously submitted to MMS (including material submitted in compliance with prior regulations).
(c) The application shall include a list of every lessee and right-of-way holder whose lease or right-of-way is intersected by the proposed right-of-way. The application shall also include a statement that a copy of the application has been sent by registered or certified mail to each such lessee or right-of-way holder.
(d) The applicant shall include in the application an original and three copies of a completed Nondiscrimination in Employment form (YN 3341-1 dated July 1982). These forms are available at each MMS regional office.
(a) In considering an application for a right-of-way, the Regional Supervisor
(b) Should the proposed route of a right-of-way adjoin and subsequently cross any State submerged lands, the applicant shall submit evidence to the Regional Supervisor that the State(s) so affected has reviewed the application. The applicant shall also submit any comment received as a result of that review. In the event of a State recommendation to relocate the proposed route, the Regional Supervisor may consult with the appropriate State officials.
(c)(1) The applicant shall submit photocopies of return receipts to the Regional Supervisor that indicate the date that each lessee or right-of-way holder referenced in § 250.1010(c) of this part has received a copy of the application. Letters of no objection may be submitted in lieu of the return receipts.
(2) The Regional Supervisor shall not take final action on a right-of-way application until the Regional Supervisor is satisfied that each such lessee or right-of-way holder has been afforded at least 30 days from the date determined in paragraph (c)(1) of this section in which to submit comments.
(d) If a proposed right-of-way crosses any lands not subject to disposition by mineral leasing or restricted from oil and gas activities, it shall be rejected by the Regional Supervisor unless the Federal Agency with jurisdiction over such excluded or restricted area gives its consent to the granting of the right-of-way. In such case, the applicant, upon a request filed within 30 days after receipt of the notification of such rejection, shall be allowed an opportunity to eliminate the conflict.
(e)(1) If the application and other required information are found to be in compliance with applicable laws and regulations, the right-of-way may be granted. The Regional Supervisor may prescribe, as conditions to the right-of-way grant, stipulations necessary to protect human, marine, and coastal environments, life (including aquatic life), property, and mineral resources located on or adjacent to the right-of-way.
(2) If the Regional Supervisor determines that a change in the application should be made, the Regional Supervisor shall notify the applicant that an amended application shall be filed subject to stipulated changes. The Regional Supervisor shall determine whether the applicant shall deliver copies of the amended application to other parties for comment.
(3) A decision to reject an application shall be in writing and shall state the reasons for the rejection.
(a) Failure to construct the associated right-of-way pipeline within 5 years of the date of the granting of a right-of-way shall cause the grant to expire.
(b)(1) A right-of-way holder shall ensure that the right-of-way pipeline is constructed in a manner that minimizes deviations from the right-of-way as granted.
(2) If, after constructing the right-of-way pipeline, it is determined that a deviation from the proposed right-of-way as granted has occurred, the right-of-way holder shall—
(i) Notify the operators of all leases and holders of all right-of-way grants in which a deviation has occurred, and
(ii) Relinquish any unused portion of the right-of-way.
(3) Substantial deviation of a right-of-way pipeline as constructed from the proposed right-of-way as granted may be grounds for forfeiture of the right-of-way.
(c) If the Regional Supervisor determines that a significant change in conditions has occurred subsequent to the granting of a right-of-way but prior to the commencement of construction of the associated pipeline, the Regional Supervisor may suspend or temporarily prohibit the commencement of construction until the right-of-way grant is modified to the extent necessary to address the changed conditions.
(a) Assignment may be made of a right-of-way grant, in whole or of any lineal segment thereof, subject to the approval of the Regional Supervisor. An application for approval of an assignment of a right-of-way or of a lineal segment thereof, shall be filed in triplicate with the Regional Supervisor.
(b) Any application for approval for an assignment, in whole or in part, of any right, title, or interest in a right-of-way grant shall be accompanied by the same showing of qualifications of the assignees as is required of an applicant for a right-of-way in § 250.1010 of this subpart and shall be supported by a statement that the assignee agrees to comply with and to be bound by the terms and conditions of the right-of-way grant. The assignee shall satisfy the bonding requirements in § 250.1009(b) of this part. No transfer shall be recognized unless and until it is first approved, in writing, by the Regional Supervisor. A nonrefundable filing fee of $60 must accompany the application for the approval of an assignment. MMS periodically will amend the filing fee based on its experience with the costs for administering pipeline right-of-way assignment applications. If the costs increase by more than the CPI “U,” MMS will provide notice and opportunity for comment before changing the filing fee. For lesser cost increases or cost reductions MMS will change the fee without such procedures.
A right-of-way grant or a portion thereof may be surrendered by the holder by filing a written relinquishment in triplicate with the Regional Supervisor. It shall contain those items addressed in § 250.1007(c) of this part. A relinquishment shall take effect on the date it is filed subject to the satisfaction of all outstanding debts, fees, or fines and the requirements in § 250.1009(c)(9) of this part.
Terms used in this subpart shall have meanings given below:
(a) Wells and reservoirs shall be produced at rates that will provide economic development and depletion of the hydrocarbon resources in a manner that would maximize the ultimate recovery without adversely affecting correlative rights.
(b) For directionally drilled wells in which the completed interval is closer than 500 feet from a unit or lease line or for vertically drilled wells in which the surface location is closer than 500 feet from a unit or lease line, for which the unit, lease, or royalty interests are not the same, the prior approval by the Regional Supervisor is required before production is commenced. An operator requesting such an approval shall furnish the Regional Supervisor with letters expressing acceptance or objection from operators of offset properties.
(c) The lessee shall propose a classification for each reservoir as an oil reservoir, an oil reservoir with an associated gas cap or a gas reservoir, and as sensitive or nonsensitive.
(d) All oil reservoirs with associated gas caps shall be initially classified as sensitive and shall require establishing a maximum efficient production rate and balancing of production in accordance with § 250.1102(a) (1) and (5) of this part. All other oil reservoirs and all gas reservoirs shall be initially classified as nonsensitive.
(e) A reservoir may be reclassified by the Minerals Management Service (MMS) as to type and sensitivity at any time during its productive life when information becomes available showing that reclassification is warranted.
(a)
(2) The lessee may propose to revise an MER by submitting Form MMS-127 with appropriate supporting information.
(3) The effective date of an MER for a reservoir or revision thereof shall be the first day of the month in which Form MMS-127 is submitted.
(4) When approved, the MER shall not be exceeded, except as provided in paragraph (a)(5) of this section.
(5) If a reservoir is produced at a rate in excess of the MER for any month, the lessee should initiate measures necessary to balance production (offset overproduction by underproduction) during the next succeeding month. All overproduction shall be balanced by the end of the next succeeding calendar quarter following the quarter in which the overproduction occurred. Any operation in an overproduction status in
(6) The lessee shall review the MER for each producing sensitive reservoir at least once a year and submit Form MMS-127 with appropriate supporting information.
(7) The lessee may request the reclassification of a reservoir from sensitive to nonsensitive and request approval for termination of an MER by submitting Form MMS-127 with information supporting the reclassification and termination.
(8) At the request of the Regional Supervisor, the lessee shall furnish the information specified on Form MMS-127 for any producing nonsensitive reservoir.
(9) Public information copies of Form MMS-127 shall be submitted in accordance with § 250.190.
(b)
(2) The lessee shall conduct a well-flow potential test within 30 days of the date of first continuous production on all new, recompleted, and reworked well completions. Within 15 days after the end of the test period, the lessee must submit a proposed MPR with well potential test for the individual well completion on Form MMS-126, Well Potential Test Report. The initial MPR shall not exceed 110 percent of the test rate submitted and shall be effective on the first day of the month following the end of the test period if approved by the Regional Supervisor. During the 30-day period allowed for testing, the lessee may produce a new, recompleted, or reworked completion at rates necessary to establish the MPR. After the 30-day period and prior to approval of the initial MPR, a well completion may be produced at a rate not to exceed the proposed rate. The lessee shall report the total production obtained during the test period and shall identify all other wells completed in the reservoir on Form MMS-126.
(3) At least one well test shall be conducted during a calendar half for producing oil-well and gas-well completions and results submitted on Form MMS-128, Semiannual Well Test Report. Well tests shall be submitted within 45 days of the day the test was conducted.
(4) Unless otherwise ordered by the Regional Supervisor, a revised MPR shall automatically be approved for each well completion for each well test submitted equal to 110 percent of the test rate. The revised MPR will be effective on the first day of the month following the date the well test was conducted. Prior to the approval of a proposed increase of the MPR, a well completion may be produced at a rate not to exceed the proposed increased rate.
(5) When a well test is not submitted during a calendar half for a producing oil-well or gas-well completion, the MPR will be automatically canceled effective on the first day of the appropriate following calendar half.
(6) When the results of a semiannual well test for an oil-well or gas-well completion cannot be submitted within the specified time, the lessee shall request an extension of time for submitting those test results. The extension must be approved in advance by the Regional Supervisor to continue production under the last approved MPR.
(7) When approved by the Regional Supervisor, an MPR shall not be exceeded, except as provided in paragraphs (b)(4) and (c) of this section.
(8) Public Information copies of Form MMS-126 shall be submitted in accordance with § 250.190.
(9) Public information copies of Form MMS-128 shall be submitted in accordance with § 250.190.
(c)
(a) The required well testing shall be conducted for a period of not less than four consecutive hours. Immediately prior to the 4-hour test period, the well completion shall have produced under stabilized conditions for a period of not less than six consecutive hours. The 6-hour pretest period shall not begin until after the recovery of a volume of fluid equivalent to the amount of fluids introduced into the formation during completion, recompletion, reworking, or treatment operations. Measured gas volumes shall be adjusted to the standard conditions of 14.73 pounds per square inch absolute (psia) (15.025 psia in the Gulf of Mexico OCS Region) and 60
(b) At the request of the Regional Supervisor, the lessee shall conduct a multipoint back-pressure test to determine the theoretical open-flow potential of a gas well. The test shall be conducted within 30 days of the Regional Supervisor's request or within the time period specified by the Regional Supervisor.
(c) An MMS representative may witness any well test of oil-well and gas-well completions. Upon request, a lessee shall provide advance notice to the Regional Supervisor of the time and date of well tests.
(a) For each new reservoir, the lessee shall conduct a static bottomhole pressure survey within 3 months after the date of first continuous production.
(b) For each producing reservoir with three or more producing completions, the lessee shall conduct annual static bottomhole pressure surveys in a sufficient number of key wells to establish an average reservoir pressure. The Regional Supervisor may require that a survey be performed on specific wells.
(c) The results of all static bottomhole pressure surveys obtained by the lessee shall be filed with the Regional Supervisor within 60 days after the date of the survey.
(a) Lessees may flare or vent oil-well gas or gas-well gas without receiving prior approval from the Regional Supervisor only in the following situations:
(1) When gas vapors are flared or vented in small volumes from storage vessels or other low-pressure production vessels and cannot be economically recovered.
(2) During an equipment failure or to relieve system pressures. The lessee must comply with the following conditions:
(i) Lessees must not flare or vent oil-well gas for more than 48 continuous hours unless the Regional Supervisor approves. The Regional Supervisor may specify a limit of less than 48 hours to prevent air quality degradation.
(ii) Lessees must not flare or vent gas from a facility for more than 144 cumulative hours during any calendar month unless the Regional Supervisor approves.
(iii) Lessees must not flare or vent gas-well gas beyond the time required to eliminate an emergency unless the Regional Supervisor approves.
(3) During the unloading or cleaning of a well, drill-stem testing, production testing, or other well-evaluation testing. Flaring or venting must not exceed 48 cumulative hours per testing operation on a single completion. The Regional Supervisor may allow less time to prevent air quality degradation
(b) Lessees may flare or vent oil-well gas for up to 1 year when the Regional Supervisor approves the request for one of the following reasons:
(1) The lessee initiated an action which, when completed, will eliminate flaring and venting; or
(2) The lessee submitted an evaluation supported by engineering, geologic, and economic data indicating that either:
(i) The oil and gas produced from the well(s) will not economically support the facilities necessary to save and/or sell the gas; or
(ii) There is not enough gas to market.
(c) Lessees may burn produced liquid hydrocarbons only if the Regional Supervisor approves. To burn produced liquid hydrocarbons, the lessee must demonstrate that the amounts to burn would be minimal, or that the alternatives are infeasible or pose a significant risk that may harm offshore personnel or the environment. Alternatives to burning liquid hydrocarbons include transporting the liquids or storing and re-injecting them into a producible zone.
(d) Lessees must prepare records detailing gas flaring or venting and liquid hydrocarbon burning for each facility. The records must include, at a minimum:
(1) Daily volumes of gas flared or vented and liquid hydrocarbons burned;
(2) Number of hours of flaring, venting, or burning on a daily basis;
(3) Reasons for flaring, venting, or burning; and
(4) A list of the wells contributing to flaring, venting, or burning, along with the gas-oil ratio data.
(e) Lessees must keep these records for at least 2 years. Lessees must allow Minerals Management Service representatives to inspect the records at the lessees’ field office that is nearest the Outer Continental Shelf facility, or at another location agreed to by the Regional Supervisor. If the Regional Supervisor requests to see the records, lessees must provide a copy.
(f)
(ii) If the Regional Supervisor determines that flaring at a facility or group of facilities may significantly affect the air quality of an onshore area, the Regional Supervisor may require the operator(s) to conduct an air quality modeling analysis to determine the potential effect of facility emissions on onshore ambient concentrations of SO
(2)
(3)
(i) On a daily basis, the volume and duration of each flaring episode;
(ii) H
(iii) Calculated amount of SO
(a) An application to commingle hydrocarbons produced from multiple reservoirs within a common wellbore shall be submitted to the Regional Supervisor for approval and shall include all pertinent well information, geologic and reservoir engineering data, and a schematic diagram of well equipment.
(b) For a competitive reservoir, notice of intent to submit the application shall be sent by the applicant to all other lessees having an interest in the reservoir prior to submitting the application to the Regional Supervisor.
(c) The application shall specify the well-completion number to be used for subsequent reporting purposes.
(a) The lessee shall timely initiate enhanced oil and gas recovery operations for all competitive and noncompetitive reservoirs where such operations would result in an increased ultimate recovery of oil or gas under sound engineering and economic principles.
(b) A proposed plan for pressure maintenance, secondary and tertiary recovery, cycling, and similar recovery operations to increase the ultimate recovery of oil and/or gas from a reservoir shall be submitted to the Regional Supervisor for approval before such operations are initiated.
(c) Periodic reports of the volumes of oil, gas, or other substances injected, produced, or reproduced shall be submitted as required by the Regional Supervisor.
The table in this section lists questions concerning Oil and Gas Production Measurement, Surface Commingling, and Security.
Terms not defined in this section have the meanings given in the applicable chapter of the API MPMS, which is incorporated by reference in 30 CFR 250.198. Terms used in Subpart L have the following meaning:
(a)
(1) Submit a written application to, and obtain approval from, the Regional Supervisor before commencing liquid hydrocarbon production or making changes to previously approved measurement procedures;
(2) Use measurement equipment that will accurately measure the liquid hydrocarbons produced from a lease or unit;
(3) Use procedures and correction factors according to the applicable chapters of the API MPMS as incorporated by reference in 30 CFR 250.198, when obtaining net standard volume and associated measurement parameters; and
(4) When requested by the Regional Supervisor, provide the pipeline (retrograde) condensate volumes as allocated to the individual leases or units.
(b)
(1) Ensure that the royalty meter facilities include the following approved components (or other MMS-approved components) which must be compatible with their connected systems:
(i) A meter equipped with a nonreset totalizer;
(ii) A calibrated mechanical displacement (pipe) prover, master meter, or tank prover;
(iii) A proportional-to-flow sampling device pulsed by the meter output;
(iv) A temperature measurement or temperature compensation device; and
(v) A sediment and water monitor with a probe located upstream of the divert valve.
(2) Ensure that the royalty meter facilities accomplish the following:
(i) Prevent flow reversal through the meter;
(ii) Protect meters subjected to pressure pulsations or surges;
(iii) Prevent the meter from being subjected to shock pressures greater than the maximum working pressure; and
(iv) Prevent meter bypassing.
(3) Maintain royalty meter facilities to ensure the following:
(i) Meters operate within the gravity range specified by the manufacturer;
(ii) Meters operate within the manufacturer's specifications for maximum and minimum flow rate for linear accuracy; and
(iii) Meters are reproven when changes in metering conditions affect the meters’ performance such as changes in pressure, temperature, density (water content), viscosity, pressure, and flow rate.
(4) Ensure that sampling devices conform to the following:
(i) The sampling point is in the flowstream immediately upstream or downstream of the meter or divert valve (in accordance with the API MPMS as incorporated by reference in 30 CFR 250.198);
(ii) The sample container is vapor-tight and includes a power mixing device to allow complete mixing of the sample before removal from the container; and
(iii) The sample probe is in the center half of the pipe diameter in a vertical run and is located at least three pipe diameters downstream of any pipe fitting within a region of turbulent flow. The sample probe can be located in a horizontal pipe if adequate stream conditioning such as power mixers or static mixers are installed upstream of the probe according to the manufacturer's instructions.
(c)
(1) For royalty meters, ensure that the run tickets clearly identify all observed data, all correction factors not included in the meter factor, and the net standard volume.
(2) For royalty tanks, ensure that the run tickets clearly identify all observed data, all applicable correction factors, on/off seal numbers, and the net standard volume.
(3) Pull a run ticket at the beginning of the month and immediately after establishing the monthly meter factor or a malfunction meter factor.
(4) Send all run tickets for royalty meters and tanks to the Regional Supervisor within 15 days after the end of the month;
(d)
(1) Permit MMS representatives to witness provings;
(2) Ensure that the integrity of the prover calibration is traceable to test measures certified by the National Institute of Standards and Technology;
(3) Prove each operating royalty meter to determine the meter factor monthly, but the time between meter factor determinations must not exceed 42 days;
(4) Obtain approval from the Regional Supervisor before proving on a schedule other than monthly; and
(5) Submit copies of all meter proving reports for royalty meters to the Regional Supervisor monthly within 15 days after the end of the month.
(e)
(1) Calibrate the master meter to obtain a master meter factor before using it to determine operating meter factors;
(2) Use a fluid of similar gravity, viscosity, temperature, and flow rate as the liquid hydrocarbons that flow through the operating meter to calibrate the master meter;
(3) Calibrate the master meter monthly, but the time between calibrations must not exceed 42 days;
(4) Calibrate the master meter by recording runs until the results of two consecutive runs (if a tank prover is used) or five out of six consecutive runs (if a mechanical-displacement prover is used) produce meter factor differences of no greater than 0.0002. Lessees must use the average of the two (or the five) runs that produced acceptable results to compute the master meter factor;
(5) Install the master meter upstream of any back-pressure or reverse flow check valves associated with the operating meter. However, the master meter may be installed either upstream or downstream of the operating meter; and
(6) Keep a copy of the master meter calibration report at your field location for 2 years.
(f)
(1) Calibrate mechanical-displacement provers and tank provers at least once every 5 years according to the API MPMS as incorporated by reference in 30 CFR 250.101; and
(2) Submit a copy of each calibration report to the Regional Supervisor within 15 days after the calibration.
(g)
(1) The change in prover volume due to the effect of temperature on steel (Cts);
(2) The change in prover volume due to the effect of pressure on steel (Cps);
(3) The change in liquid volume due to the effect of temperature on a liquid (Ctl); and
(4) The change in liquid volume due to the effect of pressure on a liquid (Cpl).
(h)
(2) If you use a master meter, you must record proof runs until three consecutive runs produce a total meter factor difference of no greater than 0.0005. The flow rate through the meters during the proving must be within 10 percent of the rate at which the line meter will operate. The final meter factor is determined by averaging the meter factors of the three runs;
(3) If you use a tank prover, you must record proof runs until two consecutive runs produce a meter factor difference of no greater than .0005. The final
(4) You must apply operating meter factors forward starting with the date of the proving.
(i)
(i) Remove the meter from service and inspect it for damage or wear;
(ii) Adjust or repair the meter, and reprove it;
(iii) Apply the average of the malfunction factor and the previous factor to the production measured through the meter between the date of the previous factor and the date of the malfunction factor; and
(iv) Indicate that a meter malfunction occurred and show all appropriate remarks regarding subsequent repairs or adjustments on the proving report.
(2) If a meter fails to register production, you must:
(i) Remove the meter from service, repair and reprove it;
(ii) Apply the previous meter factor to the production run between the date of that factor and the date of the failure; and
(iii) Estimate and report unregistered production on the run ticket.
(3) If the results of a royalty meter proving exceed the run tolerance criteria and all measures excluding the adjustment or repair of the meter cannot bring results within tolerance, you must:
(i) Establish a factor using proving results made before any adjustment or repair of the meter; and
(ii) Treat the established factor like a malfunction factor (see paragraph (i)(1) of this section).
(j)
(1) Include Cpl factors in the meter factor calculation or list and apply them on the appropriate run ticket.
(2) List Ctl factors on the appropriate run ticket when the meter is not automatically temperature compensated.
(k)
(1) Take samples continuously proportional to flow or daily (use the procedure in the applicable chapter of the API MPMS as incorporated by reference in 30 CFR 250.198;
(2) For turbine meters, take the sample proportional to the flow only;
(3) Prove allocation meters monthly if they measure 50 or more barrels per day per meter; or
(4) Prove allocation meters quarterly if they measure less than 50 barrels per day per meter;
(5) Keep a copy of the proving reports at the field location for 2 years;
(6) Adjust and reprove the meter if the meter factor differs from the previous meter factor by more than 2 percent and less than 7 percent;
(7) For turbine meters, remove from service, inspect and reprove the meter if the factor differs from the previous meter factor by more than 2 percent and less than 7 percent;
(8) Repair and reprove, or replace and prove the meter if the meter factor differs from the previous meter factor by 7 percent or more; and
(9) Permit MMS representatives to witness provings.
(l)
(1) Equip each royalty and inventory tank with a vapor-tight thief hatch, a vent-line valve, and a fill line designed to minimize free fall and splashing;
(2) For royalty tanks, submit a complete set of calibration charts (tank tables) to the Regional Supervisor before using the tanks for royalty measurement;
(3) For inventory tanks, retain the calibration charts for as long as the tanks are in use and submit them to the Regional Supervisor upon request; and
(4) Obtain the volume and other measurement parameters by using correction factors and procedures in the
(a)
(b)
(1) Submit a written application to, and obtain approval from, the Regional Supervisor before commencing gas production or making changes to previously approved measurement procedures.
(2) Design, install, use, maintain, and test measurement equipment to ensure accurate and verifiable measurement. You must follow the recommendations in API MPMS as incorporated by reference in 30 CFR 250.198.
(3) Ensure that the measurement components demonstrate consistent levels of accuracy throughout the system.
(4) Equip the meter with a chart or electronic data recorder. If an electronic data recorder is used, you must follow the recommendations in API MPMS as referenced in 30 CFR 250.198.
(5) Take proportional-to-flow or spot samples upstream or downstream of the meter at least once every 6 months.
(6) When requested by the Regional Supervisor, provide available information on the gas quality.
(7) Ensure that standard conditions for reporting gross heating value (Btu) are at a base temperature of 60 °F and at a base pressure of 14.73 psia and reflect the same degree of water saturation as in the gas volume.
(8) When requested by the Regional Supervisor, submit copies of gas volume statements for each requested gas meter. Show whether gas volumes and gross Btu heating values are reported at saturated or unsaturated conditions; and
(9) When requested by the Regional Supervisor, provide volume and quality statements on dispositions other than those on the gas volume statement.
(c)
(1) Calibrate meters monthly, but do not exceed 42 days between calibrations;
(2) Calibrate each meter by using the manufacturer's specifications;
(3) Conduct calibrations as close as possible to the average hourly rate of flow since the last calibration;
(4) Retain calibration reports at the field location for 2 years, and send the reports to the Regional Supervisor upon request; and
(5) Permit MMS representatives to witness calibrations.
(d)
(1) If the readings are greater than the contractual tolerances, adjust the meter to function properly or remove it from service and replace it.
(2) Correct the volumes to the last acceptable calibration as follows:
(i) If the duration of the error can be determined, calculate the volume adjustment for that period.
(ii) If the duration of the error cannot be determined, apply the volume adjustment to one-half of the time elapsed since the last calibration or 21 days, whichever is less.
(e)
(1) You must provide the following to the Regional Supervisor upon request:
(i) A copy of the monthly gas processing plant allocation statement; and
(ii) Gross heating values of the inlet and residue streams when not reported on the gas plant statement.
(2) You must permit MMS to inspect the measurement and sampling equipment of natural gas processing plants that process Federal production.
(f)
(2) If you measure the volume, document the measurement equipment used and include the volume measured.
(3) If you estimate the volume, document the estimating method, the data used, and the volumes estimated.
(4) You must keep the documentation, including the volume data, easily obtainable for inspection at the field location for at least 2 years, and must retain the documentation at a location of your choosing for at least 7 years after the documentation is generated, subject to all other document retention and production requirements in 30 U.S.C. 1713 and 30 CFR part 212.
(5) Upon the request of the Regional Supervisor, you must provide copies of the records.
(a)
(1) Submit a written application to, and obtain approval from, the Regional supervisor before commencing the commingling of production or making changes to previously approved commingling applications.
(2) Upon the request of the Regional Supervisor, lessees who deliver State lease production into a Federal commingling system must provide volumetric or fractional analysis data on the State lease production through the designated system operator.
(b)
(1) Conduct a well test at least once every 2 months unless the Regional Supervisor approves a different frequency;
(2) Follow the well test procedures in 30 CFR part 250, Subpart K; and
(3) Retain the well test data at the field location for 2 years.
(a)
(1) Protect Federal production against production loss or theft;
(2) Post a sign at each royalty or inventory tank which is used in the royalty determination process. The sign must contain the name of the facility operator, the size of the tank, and the tank number;
(3) Not bypass MMS-approved liquid hydrocarbon royalty meters and tanks; and
(4) Report the following to the Regional Supervisor as soon as possible, but no later than the next business day after discovery:
(i) Theft or mishandling of production;
(ii) Tampering or bypassing any component of the royalty measurement facility; and
(iii) Falsifying production measurements.
(b)
(1) Seal the following components of liquid hydrocarbon royalty meter installations to ensure that tampering cannot occur without destroying the seal:
(i) Meter component connections from the base of the meter up to and including the register;
(ii) Sampling systems including packing device, fittings, sight glass, and container lid;
(iii) Temperature and gravity compensation device components;
(iv) All valves on lines leaving a royalty or inventory storage tank, including load-out line valves, drain-line valves, and connection-line valves between royalty and non-royalty tanks; and
(v) Any additional components required by the Regional Supervisor.
(2) Seal all bypass valves of gas royalty and allocation meters.
(3) Number and track the seals and keep the records at the field location for at least 2 years; and
(4) Make the records of seals available for MMS inspection.
This subpart explains how Outer Continental Shelf (OCS) leases are unitized. If you are an OCS lessee, use the regulations in this subpart for both competitive reservoir and unitization situations. The purpose of joint development and unitization is to:
(a) Conserve natural resources;
(b) Prevent waste; and/or
(c) Protect correlative rights, including Federal royalty interests.
(a)
(1) Promote and expedite exploration and development; or
(2) Prevent waste, conserve natural resources, or protect correlative rights, including Federal royalty interests, of a reasonably delineated and productive reservoir.
(b)
(1) Prevent waste;
(2) Conserve natural resources; or
(3) Protect correlative rights, including Federal royalty interests, of a reasonably delineated and productive reservoir.
(c)
(d)
(e)
(f)
(1) Its initial term has not expired;
(2) You conduct drilling, production, or well-reworking operations on your lease consistent with applicable regulations; or
(3) MMS orders or approves a suspension of production or operations for your lease.
(g)
(1) If you drill, produce or perform well-workover operations on a lease within a unit, each lease, or part of a lease, in the unit will remain active in accordance with the unit agreement. Following a discovery, if your unit ceases drilling activities for a reasonable time period between the delineation of one or more reservoirs and the
(2) When a lease in a unit agreement is beyond the primary term and the lease or unit is not producing, the lease will expire unless:
(i) You conduct a continuous drilling or well reworking program designed to develop or restore the lease or unit production; or
(ii) MMS orders or approves a suspension of operations under § 250.170.
(a) The Regional Supervisor may require you to conduct development and production operations in a competitive reservoir under either a joint Development and Production Plan or a unitization agreement. A competitive reservoir has one or more producing or producible well completions on each of two or more leases, or portions of leases, with different lease operating interests. For purposes of this paragraph, a producible well completion is a well which is capable of production and which is shut in at the well head or at the surface but not necessarily connected to production facilities and from which the operator plans future production.
(b) You may request that the Regional Supervisor make a preliminary determination whether a reservoir is competitive. When you receive the preliminary determination, you have 30 days (or longer if the Regional Supervisor allows additional time) to concur or to submit an objection with supporting evidence if you do not concur. The Regional Supervisor will make a final determination and notify you and the other lessees.
(c) If you conduct drilling or production operations in a reservoir determined competitive by the Regional Supervisor, you and the other affected lessees must submit for approval a joint plan of operations. You must submit the joint plan within 90 days after the Regional Supervisor makes a final determination that the reservoir is competitive. The joint plan must provide for the development and/or production of the reservoir. You may submit supplemental plans for the Regional Supervisor's approval.
(d) If you and the other affected lessees cannot reach an agreement on a joint Development and Production Plan within the approved period of time, each lessee must submit a separate plan to the Regional Supervisor. The Regional Supervisor will hold a hearing to resolve differences in the separate plans. If the differences in the separate plans are not resolved at the hearing and the Regional Supervisor determines that unitization is necessary under § 250.1301(b), MMS will initiate unitization under § 250.1304.
(a) You must file a request for a voluntary unit with the Regional Supervisor. Your request must include:
(1) A draft of the proposed unit agreement;
(2) A proposed initial plan of operation;
(3) Supporting geological, geophysical, and engineering data; and
(4) Other information that may be necessary to show that the unitization proposal meets the criteria of § 250.1300.
(b) The unit agreement must comply with the requirements of this part. MMS will maintain and provide a model unit agreement for you to follow. If MMS revises the model, MMS will publish the revised model in the
(c) After the Regional Supervisor accepts your unitization proposal, you, the other lessees, and the unit operator must sign and file copies of the unit agreement, the unit operating agreement, and the initial plan of operation
(a) If the Regional Supervisor determines that unitization of operations within a proposed unit area is necessary to prevent waste, conserve natural resources of the OCS, or protect correlative rights, including Federal royalty interests, the Regional Supervisor may require unitization.
(b) If you ask MMS to require unitization, you must file a request with the Regional Supervisor. You must include a proposed unit agreement as described in §§ 250.1301(d) and 250.1303(b); a proposed unit operating agreement; a proposed initial plan of operation; supporting geological, geophysical, and engineering data; and any other information that may be necessary to show that unitization meets the criteria of § 250.1300. The proposed unit agreement must include a counterpart executed by each lessee seeking compulsory unitization. Lessees who seek compulsory unitization must simultaneously serve on the nonconsenting lessees copies of:
(1) The request;
(2) The proposed unit agreement with executed counterparts;
(3) The proposed unit operating agreement; and
(4) The proposed initial plan of operation.
(c) If the Regional Supervisor initiates compulsory unitization, MMS will serve all lessees of the proposed unit area with a proposed unitization plan and a statement of reasons for the proposed unitization.
(d) The Regional Supervisor will not require unitization until MMS provides all lessees of the proposed unit area written notice and an opportunity for a hearing. If you want MMS to hold a hearing, you must request it within 30 days after you receive written notice from the Regional Supervisor or after you are served with a request for compulsory unitization from another lessee.
(e) MMS will not hold a hearing under this paragraph until at least 30 days after MMS provides written notice of the hearing date to all parties owning interests that would be made subject to the unit agreement. The Regional Supervisor must give all lessees of the proposed unit area an opportunity to submit views orally and in writing and to question both those seeking and those opposing compulsory unitization. Adjudicatory procedures are not required. The Regional Supervisor will make a decision based upon a record of the hearing, including any written information made a part of the record. The Regional Supervisor will arrange for a court reporter to make a verbatim transcript. The party seeking compulsory unitization must pay for the court reporter and pay for and provide to the Regional Supervisor within 10 days after the hearing three copies of the verbatim transcript.
(f) The Regional Supervisor will issue an order that requires or rejects compulsory unitization. That order must include a statement of reasons for the action taken and identify those parts of the record which form the basis of the decision. Any adversely affected party may appeal the final order of the Regional Supervisor under 30 CFR part 290.
This subpart explains MMS's civil penalty procedures whenever a lessee, operator or other person engaged in oil, gas, sulphur or other minerals operations in the OCS has a violation. Whenever MMS determines, on the basis of available evidence, that a violation occurred and a civil penalty review is appropriate, it will prepare a case file. MMS will appoint a Reviewing Officer.
The following table is an index of the sections in this subpart:
Terms used in this subpart have the following meaning:
The maximum civil penalty is $25,000 per day per violation.
MMS will review each of the following violations for potential civil penalties:
(a) Violations that you do not correct within the period MMS grants;
(b) Violations that MMS determines may constitute, or constituted, a threat of serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment; or
(c) Violations that cause serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment.
(d) Violations of the oil spill financial responsibility requirements at 30 CFR part 253.
MMS will develop a case file during its investigation of the violation, and forward it to a Reviewing Officer if any of the conditions in § 250.1404 exist. The Reviewing Officer will review the case file and determine if a civil penalty is
If the Reviewing Officer determines that a civil penalty should be assessed, the Reviewing Officer will send the violator a letter of notification. The letter of notification will include:
(a) The amount of the proposed civil penalty;
(b) Information on the violation(s); and
(c) Instruction on how to obtain a copy of the case file, schedule a meeting, submit information, or pay the penalty.
You have 30 calendar days after you receive the Reviewing Officer's letter to either:
(a) Request, in writing, a meeting with the Reviewing Officer;
(b) Submit additional information; or
(c) Pay the proposed civil penalty.
At the end of the 30 calendar days or after the meeting and submittal of additional information, the Reviewing Officer will review the case file, including all information you submitted, and send you a decision. The decision will include the amount of any final civil penalty, the basis for the civil penalty, and instructions for paying or appealing the civil penalty.
(a) When you receive the Reviewing Officer's final decision, you have 60 days to either pay the penalty or file an appeal in accordance with 30 CFR part 290, subpart A.
(b) If you file an appeal, you must either:
(1) Submit a surety bond in the amount of the penalty to the Regional Adjudication Office in the Region where the penalty was assessed, following instructions that the Reviewing Officer will include in the final decision; or
(2) Notify the Regional Adjudication Office, in the Region where the penalty was assessed, that you want your lease-specific/area-wide bond on file to be used as the bond for the penalty amount.
(c) If you choose the alternative in paragraph (b)(2) of this section, the Regional Director may require additional security (
(d) If you do not either pay the penalty or file a timely appeal, MMS will take one or more of the following actions:
(1) We will collect the amount you were assessed, plus interest, late payment charges, and other fees as provided by law, from the date you received the Reviewing Officer's final decision until the date we receive payment;
(2) We may initiate additional enforcement, including, if appropriate, cancellation of the lease, right-of-way, license, permit, or approval, or the forfeiture of a bond under this part; or
(3) We may bar you from doing further business with the Federal Government according to Executive Orders 12549 and 12689, and section 2455 of the Federal Acquisition Streamlining Act of 1994, 31 U.S.C. 6101. The Department of the Interior's regulations implementing these authorities are found at 43 CFR part 12, subpart D.
The table in this section lists frequently asked training questions and the location for the answers. The subjects are grouped as follows:
(a) General training requirements—§§ 250.1502 through 250.1507.
(b) Departures from training requirements—§§ 250.1508 through 250.1513.
(c) Training program accreditations—§§ 250.1514 through 250.1520 and § 250.1524.
(d) MMS testing information—§§ 250.1521 through 250.1523.
Terms used in this subpart have the following meaning:
The goal is to ensure that employees who work in the following areas receive training that results in safe and clean operations:
(a) Drilling well control;
(b) WO well control;
(c) WS well control; and
(d) Production safety systems.
You must provide training for your employees according to the table in this section.
You must give your employees documents that show they have completed the training course(s) required for their job. The employees must carry the documents or keep them at the job site.
(a) You must ensure that applicable employees complete basic or advanced well-control training at least every 2 years. For example, if your employees complete a well-control course on October 31, 1998, they must again complete the training by October 31, 2000.
(b) You must ensure that applicable employees complete basic or advanced production safety systems training at least every 3 years. For example, if your employees complete production safety systems training on October 31, 1998, they must again complete the training by October 31, 2001.
(c) You must ensure that your employees have at least the amount of training listed in the table in § 250.1505(c). The maximum number of hours per day of well control or production safety instruction time is 9 hours.
(d) For the first training course after March 7, 1997, you must ensure that your employee follows the following transition schedule table for well control.
(e) For the first training course after March 7, 1997, you must ensure that your employee follows the following transition schedule table for production.
(f) After your employee completes the transition training specified in paragraph (d) or (e) of this section, the training cycle will be 2 years for well control and 3 years for production training (as shown in § 250.1505 (a) and (b)).
You must provide training by a training organization or program approved by MMS.
You can find guidelines in the subparts shown in the following table:
MMS may grant an exception to well control or production safety systems training if:
(a) MMS determines that the exception won't jeopardize the safety of your personnel or create a hazard to the environment; and
(b) You need the exception because of unavoidable circumstances that make compliance infeasible or impractical.
Only if you ensure that the employees complete training for the new job before entering on duty.
You must ensure that temporary employees and on-the-job trainees complete the appropriate training unless a trained individual is directly supervising the employee.
A manufacturer's representative who is working on company supplied equipment must:
(a) Receive training by the manufacturer to install, service, or repair the specific safety device or safety systems; and
(b) Have an individual trained in production safety systems (who is also capable of evaluating the impact of the work done) accompany her/him.
(a) You may receive a 1-year provisional approval from MMS to use alternative training methods that may involve team or self-paced training using a computer-based system.
(b) You may receive up to 3 additional years (4 years total) from MMS to use alternative training methods (through onsite reviews).
(a) The alternative training must teach methods to operate equipment that result in safe and clean operations.
(b) MMS will determine, through onsite MMS reviews and unannounced audits during the provisional period, if the:
(1) Training environment is conducive to learning;
(2) Trainees interact effectively with the moderator or training administrator,
(3) Trainees function as a team (for well control only); and
(4) Tests are challenging and cover all important safety concepts and practical procedures to ensure safety.
(c) MMS may also speak with the trainees to determine if the trainees felt the training met their needs for their job.
MMS may accredit a training organization or program.
An accreditation is valid for a maximum of 4 years. A training organization may apply to MMS before the
(a) Two copies of the detailed plan that includes the:
(1) Curriculum;
(2) Names and credentials of the instructors;
(3) Mailing and street address of the training facility and the location of the records;
(4) Location for the simulator and lecture areas and how the training organization separates the areas;
(5) Presentation methods (video, lecture, film, etc.);
(6) Percentage of time for each presentation method;
(7) Testing procedures and a sample test; and
(8) List of any portions of the course that cover the subsea training option instead of the surface training option.
(b) Two copies of the training manual.
(c) A cross-reference that relates the requirements of this supbart to the elements in the program.
(d) A copy of the handouts.
(e) A copy of the training certificate that includes the following:
(1) Candidate's full name;
(2) Candidate's social security number,
(3) Name of the training school;
(4) Course name (e.g., basic WS well-control course);
(5) Option (surface or subsea);
(6) Training completion date;
(7) Job classification (e.g., drilling supervisor); and
(8) Certificate expiration date.
(f) Course outlines identified by:
(1) Name (e.g., “WS well-control course”);
(2) Type (basic or advanced); and
(3) Option (surface or subsea).
(g) Time (hours per student) for the following:
(1) Teaching;
(2) Using the simulator (for well control);
(3) Hands-on training (for production safety systems); and
(4) Completing the test (written and simulator).
(h) Special instruction methods for students who respond poorly to conventional training (including oral assistance).
(i) Additional materials (for the advanced training option) such as advanced training techniques or case studies.
(j) Information on the 3-D simulator or test wells:
(1) Capability for surface and/or subsea drilling well control, WO and completion training;
(2) Capability to simulate lost circulation and secondary kicks; and
(3) Types of kicks.
(a) The training organization must keep training records for each trainee for 5 years. For example, if a trainee completed a well-control course in 1996, the training organization may destroy the records at the end of the year 2001. The training organization must keep the following trainee record information:
(1) Daily attendance record including complete student sign-in sheet and makeup time;
(2) Written test and retest (including simulator test);
(3) Evaluation of the trainee's simulator test or retest;
(4) “Kill sheets” for simulator test or retest; and
(5) Copy of the trainee's certificate.
(b) Keep records of the training program for 5 years. The 5-year timeframe starts with the program approval date. For example, if a training program was accredited in 1995, at the end of the year 2000, the training organization may destroy the records for 1995. Keep the following training record information:
(1) Complete and current training program plan and a technical manual;
(2) A copy of each class roster; and
(3) Copies of schedules and schedule changes.
(c) Supply trainees with current copies of Government regulations on the training subject matter.
(d) Provide a certificate to each trainee who successfully completes training.
(e) Ensure that the subsea training option has an additional 4 hours of training and covers problems in well control when drilling with a subsea blowout preventer (BOP) stack including:
(1) Choke line friction determinations;
(2) Using marine risers;
(3) Riser collapse;
(4) Removing trapped gas from the BOP after controlling a well kick; and
(5) “U” tube effect as gas hits the choke line.
(f) Ensure that trainees who are absent from any part of a course make up the missed portion within 14 days after the end of the course before providing a written or simulator test to the trainee.
(g) Ensure that classes contain 18 or fewer candidates.
(h) Furnish a copy of the training program and plan to MMS personnel for their use during an onsite review.
(i) Submit the course schedule to the approving organization after approval of the training program, annually, and before any program changes. The schedule must include the:
(1) Name of the course;
(2) Class dates;
(3) Type of course; and
(4) Course location.
(j) Provide all basic course trainees a copy of the training manual.
(k) Provide all advanced course trainees handouts necessary to update the manuals the trainee has as a result of previous training courses.
(l) When each course ends, send MMS a letter and a class roster. The class roster must contain the following information for each trainee:
(1) Name of training organization;
(2) Course location (e.g., Thibodeaux, Louisiana);
(3) Trainee's full name;
(4) Name of course (e.g., Drilling well control or WS well control);
(5) Course type (i.e., basic or advanced training);
(6) Options (e.g., subsea);
(7) Date trainee completed course;
(8) Name(s) of instructor(s) teaching the course;
(9) The trainee's social security number;
(10) Trainee's employer;
(11) Actual job title of trainee;
(12) Job of each awarded certificate; and
(13) Test scores (including course element scores) for each successful trainee.
(m) Ensure that test scores for combination training have a separate score element for each designation and for each option. For example, training in subsea drilling and in WO would have separate test scores for the drilling, WO, and for the subsea portion.
(a) The training organization must:
(1) Administer the test at the training facility;
(2) Use 70 percent as a passing grade for each course element (drilling, well completion, etc.);
(3) Ensure that the tests are confidential and nonrepetitive;
(4) Offer a retest, when necessary, using different questions of equal difficulty;
(5) Allow open-book regulations and a formula sheet (without examples) for well control only; and
(6) Allocate no more than the following amount of time to the minimum instruction time: 1 hour for a single course, 2 hours for a combination of two basic courses, or 2.5 hours for a combination of three or more courses.
(b) A trainee who fails a retest must repeat the training and pass the test in order to work in the OCS in their job classification.
(a) The training organization must ensure that:
(1) The test simulates a surface BOP (or subsea stack for the subsea option) and the simulator is 3-D with actual gauges and dials.
(2) The instructor runs only one simulator and has a maximum of three students in each team.
(3) The simulator test time allocated to the minimum instruction time is 1
(4) The trainees are able to:
(i) Kill the well before removing the tree;
(ii) Determine slow pump rates;
(iii) Recognize kick warnings signs;
(iv) Shut in a well;
(v) Complete kill sheets;
(vi) Initiate kill procedures;
(vii) Maintain appropriate bottomhole pressure;
(viii) Maintain constant bottomhole pressure;
(ix) Recognize and handle unusual well-control situations;
(x) Control the kick as it reaches the choke line; and
(xi) Determine if kick gas or fluids are removed.
(5) In the subsea option, the trainees are able to:
(i) Determine choke line friction pressures for subsea BOP stacks; and
(ii) Discuss and demonstrate procedures such as circulating the riser and removing trapped gas in a subsea BOP stack.
(6) Offer a retest, when necessary, using different questions of equal difficulty.
(b) A trainee who fails a retest must repeat the training and pass the test to work in the OCS in their job classification.
See Table (a) of this section for well control and Table (b) of this section for production safety systems. The checks in Table (a) indicate the required training elements that apply to each job. Tables (a) and (b) follow:
(a) You must allow MMS to test employees at your worksite.
(b) You must identify your employees by:
(1) Current job classification;
(2) Name of the operator;
(3) Name of the most recent basic or advanced course taken by your employees for their current job; and
(4) Name of the training organization.
(c) You must correct any deficiencies found by MMS. Steps for correcting deficiencies may include:
(1) Isolating problems by doing more testing; and
(2) Reassigning employees or conducting training (MMS will not identify the employees it tests).
(a) Training organizations must allow MMS to test trainees.
(b) The trainee must pass the MMS-conducted test or a retest in order for MMS to consider that the trainee completed the training.
MMS needs to identify the effectiveness of a training program that provides for safe and clean operations.
Yes, an accredited organization can lose its accreditation. MMS may revoke or suspend an organization's accreditation for noncompliance with regulations or conditions of its accredited program, or assess civil penalties under subpart N of this part.
Operations to discover, develop, and produce sulphur in the OCS shall be in accordance with an approved Exploration Plan or Development and Production Plan and shall be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased or not leased), the national security or defense, and the marine, coastal, or human environment.
Terms used in this subpart shall have the meanings as defined below:
(a) The requirements of this subpart P are applicable to all exploration, development, and production operations under an OCS sulphur lease. Sulphur operations include all activities conducted under a lease for the purpose of discovery or delineation of a sulphur deposit and for the development and production of elemental sulphur. Sulphur operations also include activities
(b) Lessees conducting sulphur operations in the OCS shall comply with the requirements of the applicable provisions of subparts A, B, C, G, I, J, M, N, and O of this part.
(c) Lessees conducting sulphur operations in the OCS are also required to comply with the requirements in the applicable provisions of subparts D, E, F, H, K, and L of this part where such provisions specifically are referenced in this subpart.
(a) Upon receipt of a written request from the lessee, the District Supervisor will determine whether a sulphur deposit has been defined that contains sulphur in paying quantities (i.e., sulphur in quantities sufficient to yield a return in excess of the costs, after completion of the wells, of producing minerals at the wellheads).
(b) A determination under paragraph (a) of this section shall be based upon the following:
(1) Core analyses that indicate the presence of a producible sulphur deposit (including an assay of elemental sulphur);
(2) An estimate of the amount of recoverable sulphur in long tons over a specified period of time; and
(3) Contour map of the cap rock together with isopach map showing the extent and estimated thickness of the sulphur deposit.
Sulphur lessees shall comply with requirements of this section when conducting well-drilling, well-completion, well-workover, or production operations.
(a)
(b)
(c)
(d)
(e)
(f)
(a) Lessees of OCS sulphur leases shall conduct drilling operations in accordance with §§ 250.1605 through 250.1619 of this subpart and with other requirements of this part, as appropriate.
(b)
(2) Prior to commencing operation, drilling units shall be made available for a complete inspection by the District Supervisor.
(3) The lessee shall provide information and data on the fitness of the drilling unit to perform the proposed drilling operation. The information shall be submitted with, or prior to, the submission of Form MMS-123, Application for Permit to Drill (APD), in accordance with § 250.1617 of this subpart. After a drilling unit has been approved by an MMS district office, the information required in this paragraph need not be resubmitted unless required by the District Supervisor or there are changes in the equipment that affect the rated capacity of the unit.
(c)
(d)
(e)
(2) Inclinational surveys shall be obtained on all vertical wells at intervals not exceeding 1,000 feet during the normal course of drilling. Directional surveys giving both inclination and azimuth shall be obtained on all directionally drilled wells at intervals not exceeding 500 feet during the normal course of drilling and at intervals not exceeding 200 feet in all planned angle-change portions of the borehole.
(3) Directional surveys giving both inclination and azimuth shall be obtained on both vertically and directionally drilled wells at intervals not exceeding 500 feet prior to or upon setting a string of casing, or production liner, and at total depth. Composite directional surveys shall be prepared with the interval shown from the bottom of the conductor casing. In calculating all surveys, a correction from the true north to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north shall be made after making the magnetic-to-true-north correction. A composite dipmeter directional survey or a composite measurement while-drilling directional survey will be acceptable as fulfilling the applicable requirements of this paragraph.
(4) Wells are classified as vertical if the calculated average of inclination
(5) At the request of a holder of an adjoining lease, the Regional Supervisor may, for the protection of correlative rights, furnish a copy of the directional survey to that leaseholder.
(f)
(g)
(h)
The lessee shall take necessary precautions to keep its wells under control at all times. Operations shall be conducted in a safe and workmanlike manner. The lessee shall utilize the best available and safest drilling technologies and state-of-the-art methods to evaluate and minimize the potential for a well to flow or kick. The lessee shall utilize personnel who are trained and competent and shall utilize and maintain equipment and materials necessary to assure the safety and protection of personnel, equipment, natural resources, and the environment.
When geological and engineering information in a field enables a District Supervisor to determine specific operating requirements, field rules may be established for drilling, well completion, or well workover on the District Supervisor's initiative or in response to a request from a lessee; such rules may modify the specific requirements of this subpart. After field rules have been established, operations in the field shall be conducted in accordance with such rules and other requirements of this subpart. Field rules may be amended or canceled for cause at any time upon the initiative of the District Supervisor or upon the request of a lessee.
(a)
(i) Drive or structural,
(ii) Conductor,
(iii) Cap rock casing,
(iv) Bobtail cap rock casing (required when the cap rock casing does not penetrate into the cap rock),
(v) Second cap rock casing (brine wells), and
(vi) Production liner.
(2) The lessee shall case and cement all wells with a sufficient number of strings of casing cemented in a manner necessary to prevent release of fluids from any stratum through the wellbore (directly or indirectly) into the sea, protect freshwater aquifers from contamination, support unconsolidated sediments, and otherwise provide a means of control of the formation pressures and fluids. Cement composition, placement techniques, and waiting time shall be designed and conducted so that the cement in place behind the bottom 500 feet of casing or total length of annular cement fill, if less, attains a minimum compressive strength of 160 pounds per square inch (psi).
(3) The lessee shall install casing designed to withstand the anticipated
(4) In cases where cement has filled the annular space back to the mud line, the cement may be washed out or displaced to a depth not exceeding the depth of the structural casing shoe to facilitate casing removal upon well abandonment if the District Supervisor determines that subsurface protection against damage to freshwater aquifers and against damage caused by adverse loads, pressures, and fluid flows is not jeopardized.
(5) If there are indications of inadequate cementing (such as lost returns, cement channeling, or mechanical failure of equipment), the lessee shall evaluate the adequacy of the cementing operations by pressure testing the casing shoe. If the test indicates inadequate cementing, the lessee shall initiate remedial action as approved by the District Supervisor. For cap rock casing, the test for adequacy of cementing shall be the pressure testing of the annulus between the cap rock and the conductor casings. The pressure shall not exceed 70 percent of the burst pressure of the conductor casing or 70 percent of the collapse pressure of the cap rock casing.
(b)
(c)
(2) Conductor casing shall be cemented with a quantity of cement that fills the calculated annular space back to the mud line. Cement fill shall be verified by the observation of cement returns. In the event that observation of cement returns is not feasible, additional quantities of cement shall be used to assure fill to the mud line.
(3) Cap rock casing shall be cemented with a quantity of cement that fills the calculated annular space to at least 200 feet inside the conductor casing. When geologic conditions such as near surface fractures and faulting exist, cap rock casing shall be cemented with a quantity of cement that fills the calculated annular space to the mud line, unless otherwise approved by the District Supervisor. In brine wells, the second cap rock casing shall be cemented with a quantity of cement that fills the calculated annular space to at least 200 feet above the setting depth of the first cap rock casing.
(d)
(2) Sufficient cement shall be used to fill the annular space to the top of the bobtail cap rock casing.
(e)
(2) The production liner is not required to be cemented unless the cap rock contains oil or gas. If the cap rock contains oil or gas, sufficient cement shall be used to fill the annular space to the top of the production liner.
(a) Prior to drilling the plug after cementing, all casing strings, except the drive or structural casing, shall be pressure tested. The conductor casing shall be tested to at least 200 psi. All casing strings below the conductor casing shall be tested to 500 psi or 0.22 psi/ft, whichever is greater. (When oil or gas is not present in the cap rock, the production liner need not be cemented in place; thus, it would not be subject to pressure testing.) If the pressure declines more than 10 percent in 30 minutes or if there is another indication of a leak, the casing shall be recemented, repaired, or an additional casing string run and the casing tested again. The above procedures shall be repeated until a satisfactory test is obtained. The time, conditions of testing, and results of all casing pressure tests shall be recorded in the driller's report.
(b) After cementing any string of casing other than structural, drilling shall not be resumed until there has been a timelapse of at least 8 hours under pressure for the conductor casing string or 12 hours under pressure for all other casing strings. Cement is considered under pressure if one or more float valves are shown to be holding the cement in place or when other means of holding pressure are used.
(a)
(b)
(c)
(d)
(1) An accumulator system that provides sufficient capacity to supply 1.5 times the volume necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure, without assistance from a charging system. After February 14, 1992, accumulator regulators supplied by rig air, which do not have a secondary source of pneumatic supply, shall be equipped with manual overrides or other devices alternately provided to ensure capability of hydraulic operations if rig air is lost.
(2) An automatic backup to the accumulator system. The backup system shall be supplied by a power source independent from the power source to the primary accumulator system. The automatic backup system shall possess sufficient capability to close the BOP and hold it closed.
(3) At least one operable remote BOP control station in addition to the one on the drilling floor. This control station shall be in a readily accessible location away from the drilling floor.
(4) A drilling spool with side outlets, if side outlets are not provided in the body of the BOP stack, to provide for separate kill and choke lines.
(5) A choke line and a kill line each equipped with two full-opening valves. At least one of the valves on the choke line and one valve on the kill line shall be remotely controlled, except that a check valve may be installed on the kill line in lieu of the remotely controlled valve, provided that two readily accessible manual valves are in place and the check valve is placed between the manual valve and the pump.
(6) A fill-up line above the uppermost preventer.
(7) A choke manifold designed with consideration of anticipated pressures to which it may be subjected, method of well control to be employed, surrounding environment, and corrosiveness, volume, and abrasiveness of
(i) Manifold and choke equipment subject to well and/or pump pressure shall have a rated working pressure at least as great as the rated working pressure of the ram-type BOP's or as otherwise approved by the District Supervisor;
(ii) All components of the choke manifold system shall be protected from freezing by heating, draining, or filling with proper fluids; and
(iii) When buffer tanks are installed downstream of the choke assemblies for the purpose of manifolding the bleed lines together, isolation valves shall be installed on each line.
(8) Valves, pipes, flexible steel hoses, and other fittings upstream of, and including, the choke manifold with a pressure rating at least as great as the rated working pressure of the ram-type BOP's unless otherwise approved by the District Supervisor.
(9) A wellhead assembly with a rated working pressure that exceeds the pressure to which it might be subjected.
(10) The following system components:
(i) A kelly cock (an essentially full-opening valve) installed below the swivel and a similar valve of such design that it can be run through the BOP stack installed at the bottom of the kelly. A wrench to fit each valve shall be stored in a location readily accessible to the drilling crew;
(ii) An inside BOP and an essentially full-opening, drill-string safety valve in the open position on the rig floor at all times while drilling operations are being conducted. These valves shall be maintained on the rig floor to fit all connections that are in the drill string. A wrench to fit the drill-string safety valve shall be stored in a location readily accessible to the drilling crew;
(iii) A safety valve available on the rig floor assembled with the proper connection to fit the casing string being run in the hole; and
(iv) Locking devices installed on the ram-type preventers.
(e)
(f)
(1) One set of variable bore rams capable of sealing around both sizes in the string and one set of blind rams, or
(2) One set of pipe rams capable of sealing around the larger size string, provided that blind-shear ram capability is present, and crossover subs to the larger size pipe are readily available on the rig floor.
(a) Prior to conducting high-pressure tests, all BOP systems shall be tested to a pressure of 200 to 300 psi.
(b) Ram-type BOP's and the choke manifold shall be pressure tested with water to rated working pressure or as otherwise approved by the District Supervisor. Annular type BOP's shall be pressure tested with water to 70 percent of rated working pressure or as otherwise approved by the District Supervisor.
(c) In conjunction with the weekly pressure test of BOP systems required in paragraph (d) of this section, the choke manifold valves, upper and lower kelly cocks, and drill-string safety valves shall be pressure tested to pipe-ram test pressures. Safety valves with proper casing connections shall be actuated prior to running casing.
(d) BOP system shall be pressure tested as follows:
(1) When installed;
(2) Before drilling out each string of casing or before continuing operations in cases where cement is not drilled out;
(3) At least once each week, but not exceeding 7 days between pressure tests, alternating between control stations. If either control system is not functional, further drilling operations shall be suspended until that system becomes operable. A period of more than 7 days between BOP tests is allowed when there is a stuck drill pipe
(4) Bind and blind-shear rams shall be actuated at least once every 7 days. Closing pressure on the blind and blind-shear rams greater than necessary to indicate proper operation of the rams is not required;
(5) Variable bore-pipe rams shall be pressure tested against all sizes of pipe in use, excluding drill collars and bottomhole tools; and
(6) Following the disconnection or repair of any well-pressure containment seal in the wellhead/BOP stack assembly. In this situation, the pressure tests may be limited to the affected component.
(e) All BOP systems shall be inspected and maintained to assure that the equipment will function properly. The BOP systems shall be visually inspected at least once each day. The manufacturer's recommended inspection and maintenance procedures are acceptable as guidelines in complying with this requirement.
(f) The lessee shall record pressure conditions during BOP tests on pressure charts, unless otherwise approved by the District Supervisor. The test duration for each BOP component tested shall be sufficient to demonstrate that the component is effectively holding pressure. The charts shall be certified as correct by the operator's representative at the facility.
(g) The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP system and system components shall be recorded in the driller's report. The BOP tests shall be documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an alternate, the documentation in the driller's report may reference a BOP test plan that contains the required information and is retained on file at the facility.
(2) The control station used during the test shall be identified in the driller's report.
(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to remedy such problems or irregularities shall be noted in the driller's report.
(4) Documentation required to be entered in the driller's report may instead be referenced in the driller's report. All records, including pressure charts, driller's report, and referenced documents, pertaining to BOP tests, actuations, and inspections, shall be available for MMS review at the facility for the duration of the drilling activity. Following completion of the drilling activity, all drilling records shall be retained for a period of 2 years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the District Supervisor.
Well-control drills shall be conducted for each drilling crew in accordance with the requirements set forth in § 250.408 of this part or as approved by the District Supervisor.
(a) When drilling a conductor or cap rock hole, all drilling units shall be equipped with a diverter system consisting of a diverter sealing element, diverter lines, and control systems. The diverter system shall be designed, installed, and maintained so as to divert gases, water, mud, and other materials away from the facilities and personnel.
(b) After August 14, 1992, diverter systems shall be in compliance with the requirements of this section.
The requirements applicable to diverters that were in effect immediately prior to August 14, 1991, shall remain in effect until August 14, 1992.
(c) The diverter system shall be equipped with remote-control valves in
(d) For drilling operations conducted with a surface wellhead configuration, the following shall apply:
(1) If the diverter system utilizes only one spool outlet, branch lines shall be installed to provide downwind diversion capability, and
(2) No spool outlet or diverter line internal diameter shall be less than 10 inches, except that dual spool outlets are acceptable if each outlet has a minimum internal diameter of 8 inches, and both outlets are piped to overboard lines and that each line downstream of the changeover nipple at the spool has a minimum internal diameter of 10 inches.
(e) The diverter sealing element and diverter valves shall be pressure tested to a minimum of 200 psi when nippled upon conductor casing. No more than 7 days shall elapse between subsequent pressure tests. The diverter sealing element, diverter valves, and diverter control systems (including the remote) shall be actuation tested, and the diverter lines shall be tested for flow prior to spudding and thereafter at least once each 24-hour period alternating between control stations. All test times and results shall be recorded in the driller's report.
(a) The quantities, characteristics, use, and testing of drilling mud and the related drilling procedures shall be designed and implemented to prevent the loss of well control.
(b) The lessee shall comply with requirements concerning mud control, mud test and monitoring equipment, mud quantities, and safety precautions in enclosed mud handling areas as prescribed in § 250.410 (b), (c), (d), and (e) of this part, except that the installation of an operable degasser in the mud system as required in § 250.410(b)(8) is not required for sulphur operations.
A downhole-safety device such as a cement plug, bridge plug, or packer shall be timely installed when drilling operations are interrupted by events such as those that force evacuation of the drilling crew, prevent station keeping, or require repairs to major drilling units or well-control equipment. The use of blind-shear rams or pipe rams and an inside BOP may be approved by the District Supervisor in lieu of the above requirements if cap rock casing has been set.
(a) The lessee shall provide onsite supervision of drilling operations at all times.
(b) From the time drilling operations are initiated and until the well is completed or abandoned, a member of the drilling crew or the toolpusher shall maintain rig-floor surveillance continuously, unless the well is secured with BOP's, bridge plugs, packers, or cement plugs.
(c) Lessee and drilling contractor personnel shall be trained and qualified in accordance with the provisions of subpart O of this part. Records of specific training that lessee and drilling contractor personnel have successfully completed, the dates of completion, and the names and dates of the courses shall be maintained at the drill site.
(a) Prior to commencing the drilling of a well under an approved Exploration Plan, Development and Production Plan, or Development Operations
(b) An APD shall include rated capacities of the proposed drilling unit and of major drilling equipment. After a drilling unit has been approved for use in an MMS district, the information need not be resubmitted unless required by the District Supervisor or there are changes in the equipment that affect the rated capacity of the unit.
(c) An APD shall include a fully completed Form MMS-123 and the following:
(1) A plat, drawn to a scale of 2,000 feet to the inch, showing the surface and subsurface location of the well to be drilled and of all the wells previously drilled in the vicinity from which information is available. For development wells on a lease, the wells previously drilled in the vicinity need not be shown on the plat. Locations shall be indicated in feet from the nearest block line;
(2) The design criteria considered for the well and for well control, including the following:
(i) Pore pressure;
(ii) Formation fracture gradients;
(iii) Potential lost circulation zones;
(iv) Mud weights;
(v) Casing setting depths;
(vi) Anticipated surface pressures (which for purposes of this section are defined as the pressure that can reasonably be expected to be exerted upon a casing string and its related wellhead equipment). In the calculation of anticipated surface pressure, the lessee shall take into account the drilling, completion, and producing conditions. The lessee shall consider mud densities to be used below various casing strings, fracture gradients of the exposed formations, casing setting depths, and cementing intervals, total well depth, formation fluid type, and other pertinent conditions. Considerations for calculating anticipated surface pressure may vary for each segment of the well. The lessee shall include as a part of the statement of anticipated surface pressure the calculations used to determine this pressure during the drilling phase and the completion phase, including the anticipated surface pressure used for production string design; and
(vii) If a shallow hazards site survey is conducted, the lessee shall submit with or prior to the submittal of the APD, two copies of a summary report describing the geological and manmade conditions present. The lessee shall also submit two copies of the site maps and data records identified in the survey strategy.
(3) A BOP equipment program including the following:
(i) The pressure rating of BOP equipment,
(ii) A schematic drawing of the diverter system to be used (plan and elevation views) showing spool outlet internal diameter(s); diverter line lengths and diameters, burst strengths, and radius of curvature at each turn; valve type, size, working-pressure rating, and location; the control instrumentation logic; and the operating procedure to be used by personnel, and
(iii) A schematic drawing of the BOP stack showing the inside diameter of the BOP stack and the number of annular, pipe ram, variable-bore pipe ram, blind ram, and blind-shear ram preventers.
(4) A casing program including the following:
(i) Casing size, weight, grade, type of connection and setting depth, and
(ii) Casing design safety factors for tension, collapse, and burst with the assumptions made to arrive at these values.
(5) The drilling prognosis including the following:
(i) Estimated coring intervals,
(ii) Estimated depths to the top of significant marker formations, and
(iii) Estimated depths at which encounters with fresh water, sulphur, oil, gas, or abnormally pressured water are expected.
(6) A cementing program including type and amount of cement in cubic feet to be used for each casing string;
(7) A mud program including the minimum quantities of mud and mud materials, including weight materials, to be kept at the site;
(8) A directional survey program for directionally drilled wells;
(9) An H
(10) Such other information as may be required by the District Supervisor.
(d) Public information copies of the APD shall be submitted in accordance with § 250.190 of this part.
(a) Notices of the lessee's intention to change plans, make changes in major drilling equipment, deepen, sidetrack, or plug back a well, or engage in similar activities and subsequent reports pertaining to such operations shall be submitted to the District Supervisor on Form MMS-124, Sundry Notices and Reports on Wells. Prior to commencing operations associated with the change, written approval must be received from the District Supervisor unless oral approval is obtained pursuant to § 250.140 of this part.
(b) The Form MMS-124 submittal shall contain a detailed statement of the proposed work that will materially change from the work described in the approved APD. Information submitted shall include the present state of the well, including the production liner and last string of casing, the well depth and production zone, and the well's capability to produce. Within 30 days after completion of the work, a subsequent detailed report of all the work done and the results obtained shall be submitted.
(c) Public information copies of Form MMS-124 shall be submitted in accordance with § 250.117 of this part.
(a) Complete and accurate records for each well and all well operations shall be retained for a period of 2 years at the lessee's field office nearest the OCS facility or at another location conveniently available to the District Supervisor. The records shall contain a description of any significant malfunction or problem; all the formations penetrated; the content and character of sulphur in each formation if cored and analyzed; the kind, weight, size, grade, and setting depth of casing; all well logs and surveys run in the wellbore; and all other information required by the District Supervisor in the interests of resource evaluation, prevention of waste, conservation of natural resources, protection of correlative rights, safety of operations, and environmental protection.
(b) When drilling operations are suspended or temporarily prohibited under the provisions of § 250.170 of this part, the lessee shall, within 30 days after termination of the suspension or temporary prohibition or within 30 days after the completion of any activities related to the suspension or prohibition, transmit to the District Supervisor duplicate copies of the records of all activities related to and conducted during the suspension or temporary prohibition on, or attached to, Form MMS-125, Well Summary Report, or Form MMS-124, Sundry Notices and Reports on Wells, as appropriate.
(c) Upon request by the Regional or District Supervisor, the lessee shall furnish the following:
(1) Copies of the records of any of the well operations specified in paragraph (a) of this section;
(2) Copies of the driller's report at a frequency as determined by the District Supervisor. Items to be reported include spud dates, casing setting depths, cement quantities, casing characteristics, mud weights, lost returns, and any unusual activities; and
(3) Legible, exact copies of reports on cementing, acidizing, analyses of cores, testing, or other similar services.
(d) As soon as available, the lessee shall transmit copies of logs and charts developed by well-logging operations, directional-well surveys, and core analyses. Composite logs of multiple runs and directional-well surveys shall be transmitted to the District Supervisor in duplicate as soon as available but not later than 30 days after completion of such operations for each well.
(e) If the District Supervisor determines that circumstances warrant, the lessee shall submit any other reports and records of operations in the manner and form prescribed by the District Supervisor.
(a) Lessees shall conduct well-completion and well-workover operations in sulphur wells, bleedwells, and brine wells in accordance with §§ 250.1620 through 250.1626 of this part and other provisions of this part as appropriate (see §§ 250.501 and 250.601 of this part for the definition of well-completion and well-workover operations).
(b) Well-completion and well-workover operations shall be conducted in a manner to protect against harm or damage to life (including fish and other aquatic life), property, natural resources of the OCS including any mineral deposits (in areas leased and not leased), the national security or defense, or the marine, coastal, or human environment.
Prior to engaging in well-completion or well-workover operations, crew members shall be instructed in the safety requirements of the operations to be performed, possible hazards to be encountered, and general safety considerations to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available for MMS review.
(a) No well-completion or well-workover operation shall begin until the lessee receives written approval from the District Supervisor. Approval for such operations shall be requested on Form MMS-124. Approvals by the District Supervisor shall be based upon a determination that the operations will be conducted in a manner to protect against harm or damage to life, property, natural resources of the OCS, including any mineral deposits, the national security or defense, or the marine, coastal, or human environment.
(b) The following information shall be submitted with Form MMS-124 (or with Form MMS-123):
(1) A brief description of the well-completion or well-workover procedures to be followed;
(2) When changes in existing subsurface equipment are proposed, a schematic drawing showing the well equipment; and
(3) Where the well is in zones known to contain H
(c)(1) Within 30 days after completion, Form MMS-125, including a schematic of the tubing and the results of any well tests, shall be submitted to the District Supervisor.
(2) Within 30 days after completing the well-workover operation, except routine operations, Form MMS-124 shall be submitted to the District Supervisor and shall include the results of any well tests and a new schematic of the well if any subsurface equipment has been changed.
(a) Well-control fluids, equipment, and operations shall be designed, utilized, maintained, and/or tested as necessary to control the well in foreseeable conditions and circumstances, including subfreezing conditions. The well shall be ccntinuously monitored during well-completion and well-workover operations and shall not be left unattended at any time unless the well is shut in and secured;
(b) The following well-control fluid equipment shall be installed, maintained, and utilized:
(1) A fill-up line above the uppermost BOP,
(2) A well-control fluid-volume measuring device for determining fluid volumes when filling the hole on trips, and
(3) A recording mud-pit-level indicator to determine mud-pit-volume gains and losses. This indicator shall include both a visual and an audible warning device.
(c) When coming out of the hole with drill pipe or a workover string, the annulus shall be filled with well-control fluid before the change in fluid level decreases the hydrostatic pressure 75 psi or every five stands of drill pipe or workover string, whichever gives a lower decrease in hydrostatic pressure. The number of stands of drill pipe or workover string and drill collars that may be pulled prior to filling the hole and the equivalent well-control fluid volume shall be calculated and posted near the operator's station. A mechanical, volumetric, or electronic device for measuring the amount of well-control fluid required to fill the hole shall be utilized.
(a) The BOP system and system components and related well-control equipment shall be designed, used, maintained, and tested in a manner necessary to assure well control in foreseeable conditions and circumstances, including subfreezing conditions. The working pressure of the BOP system and system components shall equal or exceed the expected surface pressure to which they may be subjected.
(b) The minimum BOP stack for well-completion operations or for well-workover operations with the tree removed shall consist of the following:
(1) Three remote-controlled, hydraulically operated preventers including at least one equipped with pipe rams, one with blind rams, and one annular type.
(2) When a tapered string is used, the minimum BOP stack shall consist of either of the following:
(i) An annular preventer, one set of variable bore rams capable of sealing around both sizes in the string, and one set of blind rams; or
(ii) An annular preventer, one set of pipe rams capable of sealing around the larger size string, a preventer equipped with blind-shear rams, and a crossover sub to the larger size pipe that shall be readily available on the rig floor.
(c) The BOP systems for well-completion operations, or for well-workover operations with the tree removed, shall be equipped with the following:
(1) An accumulator system that provides sufficient capacity to supply 1.5 times the volume necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. After February 14, 1992, accumulator regulators supplied by rig air which do not have a secondary source of pneumatic supply shall be equipped with manual overrides or alternately other devices provided to ensure capability of hydraulic operations if rig air is lost;
(2) An automatic backup to the accumulator system supplied by a power source independent from the power source to the primary accumulator system and possessing sufficient capacity to close all BOP's and hold them closed;
(3) Locking devices for the pipe-ram preventers;
(4) At least one remote BOP-control station and one BOP-control station on the rig floor; and
(5) A choke line and a kill line each equipped with two full-opening valves and a choke manifold. One of the choke-line valves and one of the kill-line valves shall be remotely controlled except that a check valve may be installed on the kill line in lieu of the remotely-controlled valve provided that two readily accessible manual valves are in place, and the check valve is placed between the manual valve and the pump.
(d) The minimum BOP-stack components for well-workover operations with the tree in place and performed through the wellhead inside of the sulphur line using small diameter jointed pipe (usually
(1) For air line changes, the well shall be killed prior to beginning operations. The procedures for killing the well shall be included in the description of well-workover procedures in accordance with § 250.1622 of this part. Under these circumstances, no BOP equipment is required.
(2) For other work inside of the sulphur line, a tubing stripper or annular preventer shall be installed prior to beginning work.
(e) An essentially full-opening, work-string safety valve shall be maintained on the rig floor at all times during well-completion operations. A wrench to fit the work-string safety valve shall be readily available. Proper connections shall be readily available for inserting a safety valve in the work string.
(a) Prior to conducting high-pressure tests, all BOP systems shall be tested to a pressure of 200 to 300 psi.
(b) Ram-type BOP's and the choke manifold shall be pressure tested with water to a rated working pressure or as otherwise approved by the District Supervisor. Annular type BOP's shall be pressure tested with water to 70 percent of rated working pressure or as otherwise approved by the District Supervisor.
(c) In conjunction with the weekly pressure test of BOP systems required in paragraph (d) of this section, the choke manifold valves, upper and lower kelly cocks, and drill-string safety valves shall be pressure tested to pipe-ram test pressures. Safety valves with proper casing connections shall be actuated prior to running casing.
(d) BOP system shall be pressure tested as follows:
(1) When installed;
(2) Before drilling out each string of casing or before continuing operations in cases where cement is not drilled out;
(3) At least once each week, but not exceeding 7 days between pressure tests, alternating between control stations. If either control system is not functional, further drilling operations shall be suspended until that system becomes operable. A period of more than 7 days between BOP tests is allowed when there is a stuck drill pipe or there are pressure control operations, and remedial efforts are being performed, provided that the pressure tests are conducted as soon as possible and before normal operations resume. The time, date, and reason for postponing pressure testing shall be entered into the driller's report. Pressure testing shall be performed at intervals to allow each drilling crew to operate the equipment. The weekly pressure test is not required for blind and blind-shear rams;
(4) Blind and blind-shear rams shall be actuated at least once every 7 days. Closing pressure on the blind and blind-shear rams greater than necessary to indicate proper operation of the rams is not required;
(5) Variable bore-pipe rams shall be pressure tested against all sizes of pipe in use, excluding drill collars and bottomhole tools; and
(6) Following the disconnection or repair of any well-pressure containment seal in the wellhead/BOP stack assembly, the pressure tests may be limited to the affected component.
(e) All personnel engaged in well-completion operations shall participate in a weekly BOP drill to familiarize crew members with appropriate safety measures.
(f) The lessee shall record pressure conditions during BOP tests on pressure charts, unless otherwise approved by the District Supervisor. The test duration for each BOP component tested shall be sufficient to demonstrate that the component is effectively holding pressure. The charts shall be certified as correct by the operator's representative at the facility.
(g) The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP system and system components shall be recorded in the operations log. The BOP tests shall be documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an alternate, the documentation in the operations log may reference a BOP test plan that contains the required information and is retained on file at the facility.
(2) The control station used during the test shall be identified in the operations log.
(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to remedy such problems or irregularities shall be noted in the operations log.
(4) Documentation required to be entered in the driller's report may instead be referenced in the driller's report. All records, including pressure charts, driller's report, and referenced documents, pertaining to BOP tests, actuations, and inspections shall be available for MMS review at the facility for the duration of the drilling activity. Following completion of the drilling activity, all drilling records shall be retained for a period of 2 years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the District Supervisor.
(a) No tubing string shall be placed into service or continue to be used unless such tubing string has the necessary strength and pressure integrity and is otherwise suitable for its intended use.
(b) Wellhead, tree, and related equipment shall be designed, installed, tested, used, and maintained so as to achieve and maintain pressure control.
(a) The lessee shall conduct sulphur production operations in compliance with the approved Development and Production Plan requirements of §§ 250.1627 through 250.1634 of this subpart and requirements of this part, as appropriate.
(b) Production safety equipment shall be designed, installed, used, maintained, and tested in a manner to assure the safety of operations and protection of the human, marine, and coastal environments.
(a)
(b)
(1) A schematic flow diagram showing size, capacity, design, working pressure of separators, storage tanks, compressor pumps, metering devices, and other sulphur-handling vessels;
(2) A schematic piping diagram showing the size and maximum allowable working pressures as determined in accordance with API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems;
(3) Electrical system information including a plan of each platform deck, outlining all hazardous areas classified according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, and outlining areas in which potential ignition sources are to be installed;
(4) Certification that the design for the mechanical and electrical systems to be installed were approved by registered professional engineers. After these systems are installed, the lessee shall submit a statement to the District Supervisor certifying that the new installations conform to the approved designs of this subpart.
(c)
(d)
(1) A schematic flow diagram showing size, capacity, design, working pressure of separators, storage tanks, compressor pumps, metering devices, and other hydrocarbon-handling vessels;
(2) A schematic flow diagram (API RP 14C, Figure E1) and the related Safety Analysis Function Evaluation chart (API RP 14C, subsection 4.3c);
(3) A schematic piping diagram showing the size and maximum allowable working pressures as determined in accordance with API RP 14E, Design and lnstallation of Offshore Production Platform Piping Systems;
(4) Electrical system information including the following:
(i) A plan of each platform deck, outlining all hazardous areas classified according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Divisions 2, or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2, and outlining areas in which potential ignition sources are to be installed;
(ii) All significant hydrocarbon sources and a description of the type of decking, ceiling, walls (e.g., grating or solid), and firewalls; and
(iii) Elementary electrical schematic of any platform safety shutdown system with a functional legend.
(5) Certification that the design for the mechanical and electrical systems to be installed was approved by registered professional engineers. After these systems are installed, the lessee shall submit a statement to the District Supervisor certifying that the new installations conform to the approved designs of this subpart; and
(6) Design and schematics of the installation and maintenance of all fire- and gas-detection systems including the following:
(i) Type, location, and number of detection heads;
(ii) Type and kind of alarm, including emergency equipment to be activated;
(iii) Method used for detection;
(iv) Method and frequency of calibration; and
(v) A functional block diagram of the detection system, including the electric power supply.
(a)
(b)
(i) Pressure safety relief valves shall be designed, installed, and maintained in accordance with applicable provisions of sections I, IV, and VIII of the ANSI/ASME Boiler and Pressure Vessel Code. The safety relief valves shall conform to the valve-sizing and pressure-relieving requirements specified in these documents; however, the safety relief valves shall be set no higher than the maximum-allowable working pressure of the vessel. All safety relief valves and vents shall be piped in such a way as to prevent fluid from striking personnel or ignition sources.
(ii) The lessee shall use pressure recorders to establish the operating pressure ranges of pressure vessels in order to establish the pressure-sensor settings. Pressure-recording charts used to determine operating pressure ranges shall be maintained by the lessee for a period of 2 years at the lessee's field office nearest the OCS facility or at another location conveniently available to the District Supervisor. The high-pressure sensor shall be set no higher than 15 percent or 5 psi, whichever is greater, above the highest operating pressure of the vessel. This setting shall also be set sufficiently below (15 percent or 5 psi, whichever is greater) the safety relief valve's set pressure to assure that the high-pressure sensor sounds an alarm before the safety relief valve starts relieving. The low-pressure sensor shall sound an alarm no lower than 15 percent or 5 psi, whichever is greater, below the lowest pressure in the operating range.
(2)
(3)
(i) A firewater system consisting of rigid pipe with firehose stations shall be installed. The firewater system shall be installed to provide needed protection, especially in areas where fuel handling equipment is located.
(ii) Fuel or power for firewater pump drivers shall be available for at least 30 minutes of run time during platform shut-in time. If necessary, an alternate fuel or power supply shall be installed to provide for this pump-operating time unless an alternate firefighting system has been approved by the District Supervisor;
(iii) A firefighting system using chemicals may be used in lieu of a water system if the District Supervisor determines that the use of a chemical system provides equivalent fire-protection control; and
(iv) A diagram of the firefighting system showing the location of all firefighting equipment shall be posted in a prominent place on the facility or structure.
(4)
(ii) All detection systems shall be capable of continuous monitoring. Fire-
(iii) A fuel-gas odorant or an automatic gas-detection and alarm system is required in enclosed, continuously manned areas of the facility that are provided with fuel gas. Living quarters and doghouses not containing a gas source and not located in a classified area do not require a gas detection system.
(iv) The District Supervisor may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(v) Fire- and gas-detection systems shall be an approved type, designed and installed in accordance with API RP 14C, API RP 14G, and API RP 14F, Recommended Practice for Design and Installation of Electrical Systems for Offshore Production Platforms.
(c)
(a)
(1) Safety relief valves on the natural gas feed system for power plant operations such as pressure safety valves shall be inspected and tested for operation at least once every 12 months. These valves shall be either bench tested or equipped to permit testing with an external pressure source.
(2) The following safety devices shall be inspected and tested at least once each calendar month, but at no time shall more than 6 weeks elapse between tests:
(i) All pressure safety high or pressure safety low, and
(ii) All level safety high and level safety low controls.
(3) All pumps for firewater systems shall be inspected and operated weekly.
(4) All fire- (flame, heat, or smoke) and gas-detection systems shall be inspected and tested for operation and recalibrated every 3 months provided that testing can be performed in a nondestructive manner.
(5) Prior to the commencement of production, the lessee shall notify the District Supervisor when the lessee is ready to conduct a preproduction test and inspection of the safety system. The lessee shall also notify the District Supervisor upon commencement of production in order that a complete inspection may be conducted.
(b)
Prior to engaging in production operations on a lease and periodically thereafter, personnel installing, inspecting, testing, and maintaining safety devices shall be instructed in
Each sulphur deposit shall be produced at rates that will provide economic development and depletion of the deposit in a manner that would maximize the ultimate recovery of sulphur without resulting in waste (e.g., an undue reduction in the recovery of oil and gas from an associated hydrocarbon accumulation).
(a)
(b)
(a) All locations where sulphur is produced, measured, or stored shall be operated and maintained to ensure against the loss or theft of produced sulphur and to assure accurate and complete measurement of produced sulphur for royalty purposes.
(b) Evidence of mishandling of produced sulphur from an offshore lease, or tampering or falsifying any measurement of production for an offshore lease, shall be reported to the Regional Supervisor as soon as possible but no later than the next business day after discovery of the evidence of mishandling.
43 U.S.C. 1331
Terms used in this part have the following meaning:
(1) Geological and geophysical marine and airborne surveys where magnetic, gravity, seismic reflection, seismic refraction, gas sniffers, coring, or other systems are used to detect or imply the presence of oil, gas, or sulphur; and
(2) Any drilling, whether on or off a geological structure.
(1) Geological exploration for mineral resources;
(2) Geophysical exploration for mineral resources;
(3) Geological scientific research; or
(4) Geophysical scientific research.
(a) To allow you to conduct G&G activities in the OCS related to oil, gas, and sulphur on unleased lands or on lands under lease to a third party.
(b) To ensure that you carry out G&G activities in a safe and environmentally sound manner so as to prevent harm or damage to, or waste of, any natural resources (including any mineral deposit in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human environment.
(c) To inform you and third parties of your legal and contractual obligations.
(d) To inform you and third parties of the U.S. Government's rights to access G&G data and information collected under permit in the OCS, reimbursement for submittal of data and information, and the proprietary terms of data and information submitted to, and retained by, MMS.
MMS authorizes you to conduct exploration or scientific research activities under this part in accordance with the Act, the regulations in this part, orders of the Director/Regional Director, and other applicable statutes, regulations, and amendments.
(a) This part does not apply to G&G exploration conducted by or on behalf of the lessee on a lease in the OCS. Refer to 30 CFR part 250 if you plan to conduct G&G activities related to oil, gas, or sulphur under terms of a lease.
(b) Federal agencies are exempt from the regulations in this part.
(c) G&G exploration or G&G scientific research related to minerals other than oil, gas, and sulphur is covered by regulations at 30 CFR part 280.
(a)
(b)
(1)
(i) Using solid or liquid explosives;
(ii) Drilling a deep stratigraphic test; or
(iii) Developing data and information for proprietary use or sale.
(2)
(a)
(b)
(c)
(1) The name(s) of the person(s) who will conduct the proposed research;
(2) The name(s) of any other person(s) participating in the proposed research, including the sponsor;
(3) The type of research and a brief description of how you will conduct it;
(4) The location in the OCS, indicated on a map, plat, or chart, where you will conduct research;
(5) The proposed dates you project for your research activity to start and end;
(6) The name, registry number, registered owner, and port of registry of vessels used in the operation;
(7) The earliest practicable time you expect to make the data and information resulting from your research activity available to the public;
(8) Your plan of how you will make the data and information you collected available to the public;
(9) That you and others involved will not sell or withhold for exclusive use the data and information resulting from your research; and
(10) At your option, you may submit (as a substitute for the material required in paragraphs (c)(7), (c)(8), and (c)(9) of this section) the nonexclusive use agreement for scientific research attachment to Form 327.
(d)
(1) For the OCS off the State of Alaska—the Regional Supervisor for Resource Evaluation, Minerals Management Service, Alaska OCS Region, 949 East 36th Avenue, Anchorage, Alaska 99508-4302.
(2) For the OCS off the Atlantic Coast and in the Gulf of Mexico—the Regional Supervisor for Resource Evaluation, Minerals Management Service, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New Orleans, Louisiana 70123-2394.
(3) For the OCS off the coast of the States of California, Oregon, Washington, or Hawaii—the Regional Supervisor for Resource Evaluation, Minerals Management Service, Pacific OCS Region, 770 Paseo Camarillo, Camarillo, California 93010-6064.
While conducting G&G exploration or scientific research activities under MMS permit or Notice:
(a) You must not:
(1) Interfere with or endanger operations under any lease, right-of-way, easement, right-of-use, Notice, or permit issued or maintained under the Act;
(2) Cause harm or damage to life (including fish and other aquatic life), property, or to the marine, coastal, or human environment;
(3) Cause harm or damage to any mineral resource (in areas leased or not leased);
(4) Cause pollution;
(5) Disturb archaeological resources;
(6) Create hazardous or unsafe conditions; or
(7) Unreasonably interfere with or cause harm to other uses of the area.
(b) You must immediately report to the Regional Director if you:
(1) Detect hydrocarbon occurrences;
(2) Detect environmental hazards which imminently threaten life and property; or
(3) Adversely affect the environment, aquatic life, archaeological resources, or other uses of the area where you are conducting exploration or scientific research activities.
(c) You must also consult and coordinate your G&G activities with other users of the area for navigation and safety purposes.
(d) Any persons conducting shallow test drilling or deep stratigraphic test drilling activities under a permit must use the best available and safest technologies that the Regional Director determines to be economically feasible.
(e) You may not claim any oil, gas, sulphur, or other minerals you discover while conducting operations under a permit or Notice.
(a)
(1) Gather and submit seismic, bathymetric, sidescan sonar, magnetometer, or other geophysical data and information to determine shallow structural detail across and in the vicinity of the proposed test.
(2) Submit information for coastal zone consistency certification according to paragraphs (b)(3) and (b)(4) of this section, and for protecting archaeological resources according to paragraph (b)(5) of this section.
(3) Allow all interested parties the opportunity to participate in the shallow test according to paragraph (c) of this section, and meet bonding requirements according to paragraph (d) of this section.
(b)
(1)
(i) The proposed type, sequence, and timetable of drilling activities;
(ii) A description of your drilling rig, indicating the important features with special attention to safety, pollution prevention, oil-spill containment and cleanup plans, and onshore disposal procedures;
(iii) The location of each deep stratigraphic test you will conduct, including the location of the surface and projected bottomhole of the borehole;
(iv) The types of geological and geophysical survey instruments you will use before and during drilling;
(v) Seismic, bathymetric, sidescan sonar, magnetometer, or other geophysical data and information sufficient to evaluate seafloor characteristics, shallow geologic hazards, and structural detail across and in the vicinity of the proposed test to the total depth of the proposed test well; and
(vi) Other relevant data and information that the Regional Director requires.
(2)
(i) A summary with data and information available at the time you submitted the related drilling plan. MMS will consider site-specific data and information developed since the most recent environmental impact statement or other environmental impact analysis in the immediate area. The summary must meet the following requirements:
(A) You must concentrate on the issues specific to the site(s) of drilling activity. However, you only need to summarize data and information discussed in any environmental reports, analyses, or impact statements prepared for the geographic area of the drilling activity.
(B) You must list referenced material. Include brief descriptions and a statement of where the material is available for inspection.
(C) You must refer only to data that are available to MMS.
(ii) Details about your project such as:
(A) A list and description of new or unusual technologies;
(B) The location of travel routes for supplies and personnel;
(C) The kinds and approximate levels of energy sources;
(D) The environmental monitoring systems; and
(E) Suitable maps and diagrams showing details of the proposed project layout.
(iii) A description of the existing environment. For this section, you must include the following information on the area:
(A) Geology;
(B) Physical oceanography;
(C) Other uses of the area;
(D) Flora and fauna;
(E) Existing environmental monitoring systems; and
(F) Other unusual or unique characteristics that may affect or be affected by the drilling activities.
(iv) A description of the probable impacts of the proposed action on the environment and the measures you propose for mitigating these impacts.
(v) A description of any unavoidable or irreversible adverse effects on the environment that could occur.
(vi) Other relevant data that the Regional Director requires.
(3)
(4)
(5)
(i) If the evidence suggests that an archaeological resource may be present, you must:
(A) Locate the site of the drilling so as to not adversely affect the area where the archaeological resources may be, or
(B) Establish to the satisfaction of the Regional Director that an archaeological resource does not exist or will not be adversely affected by drilling. This must be done by further archaeological investigation, conducted by an archaeologist and a geophysicist, using survey equipment and techniques deemed necessary by the Regional Director. A report on the investigation must be submitted to the Regional Director for review.
(ii) If the Regional Director determines that an archaeological resource is likely to be present in the area that may be affected by drilling, and may be adversely affected by drilling, the Regional Director will notify you immediately. You must take no action that may adversely affect the archaeological resource unless further investigations determine that the resource is not archaeologically significant.
(iii) If you discover any archaeological resource while drilling, you must immediately halt drilling and report the discovery to the Regional Director. If investigations determine that the resource is significant, the Regional Director will inform you how to protect it.
(6)
(7)
(8)
(9)
(c)
(1)
(2)
(i) The participants must assess and distribute late participation penalties in accordance with the terms of the agreement.
(ii) For a significant hydrocarbon occurrence that the Regional Director announces to the public, the penalty for subsequent late participants may be raised to not more than 300 percent of the cost of each original participant in addition to the original share cost.
(3)
(4)
(i) Publish a summary statement that describes the approved activity in a relevant trade publication;
(ii) Forward a copy of the published statement to the Regional Director;
(iii) Allow at least 30 days from the summary statement publication date for other persons to join as original participants;
(iv) Compute the estimated cost by dividing the estimated total cost of the program by the number of original participants; and
(v) Furnish the Regional Director with a complete list of all participants before starting operations, or at the end of the advertising period if you begin operations before the advertising period is over. The names of any subsequent or late participants must also be furnished to the Regional Director.
(5)
(d)
(1) Before MMS issues a permit authorizing the drilling of a deep stratigraphic test, you must either:
(i) Furnish to MMS a bond of not less than $200,000 that guarantees compliance with all the terms and conditions of the permit; or
(ii) Maintain a $1 million bond that guarantees compliance with all the terms and conditions of the permit you hold for the OCS area where you propose to drill.
(2) You must provide additional security to MMS if the Regional Director determines that it is necessary for the permit or area.
(3) The Regional Director may require you to provide a bond, in an amount the Regional Director prescribes, before authorizing you to drill a shallow test well.
(4) Your bond must be on a form approved by the Associate Director for Offshore Minerals Management.
(a)
(b)
(c)
(2) You must submit a final report of exploration or scientific research activities under a permit within 30 days after the completion of acquisition activities under the permit. You may combine the final report with the last status report and must include each of the following:
(i) A description of the work performed.
(ii) Charts, maps, plats, and digital navigational data in a format specified by the Regional Director, showing the areas and blocks in which any exploration or permitted scientific research activities were conducted. Identify the lines of geophysical traverses and their locations including a reference sufficient to identify the data produced during each activity.
(iii) The dates on which you conducted the actual exploration or scientific research activities.
(iv) A summary of any:
(A) Hydrocarbon or sulphur occurrences encountered;
(B) Environmental hazards; and
(C) Adverse effects of the exploration or scientific research activities on the environment, aquatic life, archaeological resources, or other uses of the area in which the activities were conducted.
(v) Other descriptions of the activities conducted as specified by the Regional Director.
(a) MMS may temporarily stop exploration or scientific research activities under a permit when the Regional Director determines that:
(1) Activities pose a threat of serious, irreparable, or immediate harm. This includes damage to life (including fish and other aquatic life), property, any mineral deposit (in areas leased or not leased), to the marine, coastal, or human environment, or to an archaeological resource;
(2) You failed to comply with any applicable law, regulation, order, or provision of the permit. This would include MMS’ required submission of reports, well records or logs, and G&G data and information within the time specified; or
(3) Stopping the activities is in the interest of national security or defense.
(b)
(2) The Regional Director will advise you when you may start your permit activities again.
(c)
(1) If MMS cancels your permit, the Regional Director will advise you by certified or registered mail 30 days before the cancellation date and will state the reason.
(2) You may relinquish the permit by advising the Regional Director by certified or registered mail 30 days in advance.
(3) After MMS cancels your permit or you relinquish it, you are still responsible for proper abandonment of any drill sites in accordance with the requirements of § 251.7(b)(8). You must also comply with all other obligations specified in this part or in the permit.
(a)
(b)
(c)
(a)
(2) The Regional Director may ask if you have further analyzed, processed, or interpreted any geological data and information. When so asked, you must respond to MMS in writing within 30 days.
(b)
(c)
(1) An accurate and complete record of all geological (including geochemical) data and information describing each operation of analysis, processing, and interpretation;
(2) Paleontological reports identifying microscopic fossils by depth, including the reference datum to which paleontological sample depths are related and, if the Regional Director requests, washed samples that you maintain for paleontological determinations;
(3) Copies of well logs or charts in a digital format, if available;
(4) Results and data obtained from formation fluid tests;
(5) Analyses of core or bottom samples and/or a representative cut or split of the core or bottom sample;
(6) Detailed descriptions of any hydrocarbons or hazardous conditions encountered during operations, including near losses of well control, abnormal geopressures, and losses of circulation; and
(7) Other geological data and information that the Regional Director may specify.
(d)
(1) The third party recipient of the data and information assumes the obligations under this section, except for the notification provisions of paragraph (a)(1), and is subject to the penalty provisions of 30 CFR part 250, subpart N; and
(2) A permittee or third party that sells, trades, licenses, or otherwise provides data and information to a third party must advise the recipient, in writing, that accepting these obligations is a condition precedent of the sale, trade, license, or other agreement; and
(3) Except for license agreements, a permittee or third party that sells,
(4) For license agreements a permittee or third party that licenses data and information to a third party must, within 30 days of a request by the Regional Director, advise the Regional Director, in writing, of the license agreement, including the identity of the recipient of the data and information.
(a)
(2) The Regional Director may ask if you have further processed or interpreted any geophysical data and information. When so asked, you must respond to MMS in writing within 30 days.
(b)
(1) You must submit the geophysical data and information within 30 days of receiving the request, unless the Regional Director extends the delivery time.
(2) At any time before final selection, the Regional Director may return any or all geophysical data and information following review. You will be notified in writing of all or portions of those data the Regional Director decides to retain.
(c)
(1) An accurate and complete record of each geophysical survey conducted under the permit, including digital navigational data and final location maps;
(2) All seismic data collected under a permit presented in a format and of a quality suitable for processing;
(3) Processed geophysical information derived from seismic data with extraneous signals and interference removed, presented in a quality format suitable for interpretive evaluation, reflecting state-of-the-art processing techniques; and
(4) Other geophysical data, processed geophysical information, and interpreted geophysical information including, but not limited to, shallow and deep subbottom profiles, bathymetry, sidescan sonar, gravity and magnetic surveys, and special studies such as refraction and velocity surveys.
(d)
(1) The third party recipient of the data and information assumes the obligations under this section, except for the notification provisions of paragraph (a)(1), and is subject to the penalty provisions of 30 CFR part 250, subpart N; and
(2) A permittee or third party that sells, trades, licenses, or otherwise provides data and information to a third party must advise the recipient, in writing, that accepting these obligations is a condition precedent of the
(3) Except for license agreements, a permittee or third party that sells, trades, or otherwise provides data and information to a third party must advise the Regional Director, in writing and within 30 days, of the sale, trade, or other agreement, including the identity of the recipient of the data and information; or
(4) For license agreements, a permittee or third party that licenses data and information to a third party must, within 30 days of a request by the Regional Director, advise the Regional Director, in writing, of the license agreement, including the identity of the recipient of the data and information.
(a) MMS will reimburse you or a third party for reasonable costs of reproducing data and information that the Regional Director requests if:
(1) You deliver G&G data and information to MMS for the Regional Director to inspect or select and retain (according to §§ 251.11 or 251.12 );
(2) MMS receives your request for reimbursement and the Regional Director determines that the requested reimbursement is proper; and
(3) The cost is at your lowest rate (or a third party's) or at the lowest commercial rate established in the area, whichever is less.
(b) MMS will reimburse you or the third party for the reasonable costs of processing geophysical information (which does not include cost of data acquisition):
(1) If, at the request of the Regional Director, you processed the geophysical data or information in a form or manner other than that used in the normal conduct of business; or
(2) If you collected the information under a permit that MMS issued to you before October 1, 1985, and the Regional Director requests and retains the information.
(c) When you request reimbursement, you must identify reproduction and processing costs separately from acquisition costs.
(d) MMS will not reimburse you or a third party for data acquisition costs or for the costs of analyzing or processing geological information or interpreting geological or geophysical information.
(a)
(i) The Freedom of Information Act (5 U.S.C. 552);
(ii) The implementing regulations at 43 CFR part 2;
(iii) The Act; and
(iv) The regulations at 30 CFR parts 250 and 252.
(2) Except as specified in this section or in 30 CFR parts 250 and 252, if the Regional Director determines any data or information is exempt from public disclosure under paragraph (a) of this section, MMS will not provide the data and information to any State or to the executive of any local government or to the public, unless you and all third parties agree to the disclosure.
(3) MMS will keep confidential the identity of third party recipients of data and information collected under a permit. MMS will not release the identity unless you and the third parties agree to the disclosure.
(4) When you detect any significant hydrocarbon occurrences or environmental hazards on unleased lands during drilling operations, the Regional Director will immediately issue a public announcement. The announcement must further the national interest, but without unduly damaging your competitive position.
(b)
(1) If the data and information are not related to a deep stratigraphic test, MMS will release them to the public in accordance with the following table:
(2) If the data and information are related to a deep stratigraphic test, MMS will release them to the public at the earlier of the following times:
(i) Twenty-five years after you complete the test; or
(ii) If a lease sale is held after you complete a test well, 60 calendar days after MMS issues the first lease, any portion of which is located within 50 geographic miles (92.7 kilometers) of the test.
(c)
(1) When practical, the Regional Director will advise the person who submitted data and information under §§ 251.11 or 251.12 of the intent to disclose the data or information to an independent contractor or agent.
(2) The person so notified will have at least 5 working days to comment on the action.
(3) When the Regional Director advises the person who submitted the data and information, all other owners of the data or information will be considered to have been so notified.
(4) Before disclosure, the contractor or agent must sign a written commitment not to sell, trade, license, or disclose data or information to anyone without the Regional Director's consent.
(d)
(i) All information on the geographical, geological, and ecological characteristics of the areas and regions MMS proposes to offer for lease;
(ii) An estimate of the oil and gas reserves in the areas proposed for leasing; and
(iii) An identification of any field, geological structure, or trap on the OCS within 3 geographic miles (5.6 kilometers) of the seaward boundary of the State.
(2) After receiving nominations for leasing an area of the OCS within 3 geographic miles of the seaward boundary of any coastal State, MMS will carry out a tentative area identification according to 30 CFR part 256, subparts D and E. At that time, the Regional Director will consult with the Governor to determine whether any tracts further considered for leasing may contain any oil or gas reservoirs that underlie both the OCS and lands subject to the jurisdiction of the State.
(3) Before a sale, if a Governor requests, the Regional Director, in accordance with 30 CFR 252.7(a)(4) and (b) and sections 8(g) and 26(e) of the Act (43 U.S.C. 1337(g) and 1352(e)), will share with the Governor information that identifies potential and/or proven common hydrocarbon bearing areas within 3 geographic miles of the seaward boundary of that State.
(4) Information received and knowledge gained by a State official under paragraph (d) of this section is subject to applicable confidentiality requirements of:
(i) The Act; and
(ii) The regulations at 30 CFR parts 250, 251, and 252.
(a) The Office of Management and Budget has approved the information collection requirements in this part under 44 U.S.C. 3501
(b) We may not conduct or sponsor, and you are not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(c) We use the information collected under this part to:
(1) Evaluate permit applications and monitor scientific research activities for environmental and safety reasons.
(2) Determine that explorations do not harm resources, result in pollution, create hazardous or unsafe conditions, or interfere with other users in the area.
(3) Approve reimbursement of certain expenses.
(4) Monitor the progress and activities carried out under an OCS G&G permit.
(5) Inspect and select G&G data and information collected under an OCS G&G permit.
(d) Respondents are Federal OCS permittees and Notice filers. Responses are mandatory or are required to obtain or retain a benefit. We will protect information considered proprietary under applicable law and under regulations at § 251.14 and part 250 of this chapter.
(e) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
OCS Lands Act, 43 U.S.C. 1331 et seq., as amended, 92 Stat. 629; Freedom of Information Act, 5 U.S.C. 552; § 252.3 also issued under Pub. L. 99-190 making continuing appropriations for Fiscal Year 1986, and for other purposes.
The purpose of this part is to implement the provisions of section 26 of the Act (43 U.S.C. 1352). This part supplements the procedures and requirements contained in parts 250 and 251 of this chapter and provides procedures and requirements for the submission of oil and gas data and information resulting from exploration, development, and production operations on the Outer Continental Shelf (OCS) to the Director, Minerals Management Service. In addition, this part establishes procedures for the Director to make available certain information to the Governors of affected States and, upon request, to the executives of affected local governments in accordance with the provisions of the Freedom of Information Act and the Act.
When used in the regulations in this part, the following terms shall have the meanings given below:
(a)
(b)
(c)
(1) The laws of which are declared, pursuant to section 4(a)(2)(A) of the Act, to be the law of the United States for the portion of the OCS on which such activity is, or is proposed to be, conducted;
(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or installations and other devices permanently, or temporarily attached to the seabed;
(3) Which is receiving, or in accordance with the proposed activity will receive, oil for processing, refining, or
(4) Which is designated by the Director as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the OCS; or
(5) In which the Director finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents, to the marine or coastal environment in the event of any oilspill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities.
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
(q)
(r)
(s)
(t)
(a) Any permittee or lessee engaging in the activities of exploration for, or development and production of, oil and gas on the OCS shall provide the Director access to all data and information obtained or developed as a result of such activities, including geological data, geophysical data, analyzed geological information, processed and reprocessed geophysical information, interpreted geophysical information, and interpreted geological information. Copies of these data and information and any interpretation of these data and information shall be provided to the Director upon request. No permittee or lessee submitting an interpretation of data or information, where such interpretation has been submitted in good faith, shall be held responsible for any consequence of the use of or reliance upon such interpretation.
(b)(1) Whenever a lessee or permittee provides any data or information, at the request of the Director and specifically for use in the OCS Oil and Gas Information Program in a form and manner of processing which is utilized by the lessee or permittee in the normal conduct of business, the Director shall pay the reasonable cost of reproducing the data and information if the lessee or permittee requests reimbursement. The cost shall be computed and paid in accordance with the applicable provisions of paragraph (e)(1) of this section.
(2) Whenever a lessee or permittee provides any data or information, at the request of the Director and specifically for use in the OCS Oil and Gas Information Program, in a form and manner of processing not normally utilized by the lessee or permittee in the normal conduct of business, the Director shall pay the lessee or permittee, if the lessee or permittee requests reimbursement, the reasonable cost of processing and reproducing the requested data and information. The cost is to be computed and paid in accordance with the applicable provisions of paragraph (e)(2) of this section.
(c) Data or information requested by the Director shall be provided as soon as practicable, but not later than 30 days following receipt of the Director's request, unless, for good reason, the Director authorizes a longer time period for the submission of the requested data or information.
(d) The Director reserves the right to disclose any data or information acquired from a lessee or permittee to an independent contractor or agent for the purpose of reproducing, processing, reprocessing, or interpreting such data or information. When practicable, the Director shall notify the lessee(s) or permittee(s) who provided the data or information of the intent to disclose the data or information to an independent contractor or agent. The Director's notice of intent will afford the permittee(s) or lessee(s) a period of not less than 5 working days within which
(e)(1) After delivery of data or information in accordance with paragraph (b)(1) of this section and upon receipt of a request for reimbursement and a determination by the Director that the requested reimbursement is proper, the lessee or permittee shall be reimbursed for the cost of reproducing the data or information at the lessee's or permittee's lowest rate or at the lowest commercial rate established in the area, whichever is less. Requests for reimbursement must be made within 60 days of the delivery date of the data or information requested under paragraph (b)(1) of this section.
(2) After delivery of data or information in accordance with paragraph (b)(3) of this section, and upon receipt of a request for reimbursement and a determination by the Director that the requested reimbursement is proper, the lessee or permittee shall be reimbursed for the cost of processing or reprocessing and of reproducing the requested data or information. Requests for reimbursement must be made within 60 days of the delivery date of the data or information and shall be for only the costs attributable to processing or reprocessing and reproducing, as distinguished from the costs of data acquisition.
(3) Requests for reimbursement are to contain a breakdown of costs in sufficient detail to allow separation of reproduction, processing, and reprocessing costs from acquisition and other costs.
(f) Each Federal Department or Agency shall provide the Director with any data which it has obtained pursuant to section 11 of the Act and any other information which may be necessary or useful to assist the Director in carrying out the provisions of the Act.
(a) The Director, as soon as practicable after analysis, interpretation, and compilation of oil and gas data and information developed by the Minerals Management Service or furnished by lessees, permittees, or other government agencies, shall make available to affected States and, upon request, to the executive of any affected local government, a Summary Report of data and information designed to assist them in planning for the onshore impacts of potential OCS oil and gas development and production. The Director shall consult with affected States and other interested parties to define the nature, scope, content, and timing of the Summary Report. The Director may consult with affected States and other interested parties regarding subsequent revisions in the definition of the nature, scope, content, and timing of the Summary Report. The Summary Report shall not contain data or information which the Director determines is exempt from disclosure in accordance with this part. The Summary Report shall not contain data or information the release of which the Director determines would unduly damage the competitive position of the lessee or permittee who provided the data or information which the Director has processed, analyzed, or interpreted during the development of the Summary Report. The Summary Report shall include:
(1) Estimates of oil and gas reserves; estimates of the oil and gas resources that may be found within areas which the Secretary has leased or plans to offer for lease; and when available, projected rates and volumes of oil and gas to be produced from leased areas;
(2) Magnitude of the approximate projections and timing of development, if and when oil or gas, or both, is discovered;
(3) Methods of transportation to be used, including vessels and pipelines and approximate location of routes to be followed; and
(4) General location and nature of near-shore and onshore facilities expected to be utilized.
(b) When the Director determines that significant changes have occurred in the information contained in a Summary Report, the Director shall prepare and make available the new or revised information to each affected State, and, upon request, to the executive of any affected local government.
(a) The Director shall prepare an index of OCS information (see 30 CFR 256.10). The index shall list all relevant actual or proposed programs, plans, reports, environmental impact statements, nominations information, environmental study reports, lease sale information, and any similar type of relevant information, including modifications, comments, and revisions prepared or directly obtained by the Director under the Act. The index shall be sent to affected States and, upon request, to any affected local government. The public shall be informed of the availability of the index.
(b) Upon request, the Director shall transmit to affected States, affected local governments, and the public a copy of any information listed in the index which is subject to the control of the Minerals Management Service, in accordance with the requirements and subject to the limitations of the Freedom of Information Act (5 U.S.C. 552) and implementing regulations. The Director shall not transmit or make available any information which he determines is exempt from disclosure in accordance with this part.
(a) The Director shall make data and information available in accordance with the requirements and subject to the limitations of the Freedom of Information Act (5 U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and Testimony), the requirements of the Act, and the regulations contained in 30 CFR part 250 (Oil and Gas and Sulphur Operations in the Outer Continental Shelf) and 30 CFR part 251 (Geological and Geophysical Explorations of the Outer Continental Shelf).
(b) Except as provided in § 252.7 or in parts 250 and 251 of this chapter, no data or information determined by the director to be exempt from public disclosure under paragraph (a) of this section shall be provided to any affected State or be made available to the executive of any affected local government or to the public unless the lessee, or the permittee and all persons to whom such permittee has sold such data or information under promise of confidentiality, agree to such action.
(a)(1) The Governor of any affected State may designate an appropriate State official to inspect, at a regional location which the Director shall designate, any privileged or proprietary data or information received by the Director regarding any activity in an area adjacent to such State, except that no such inspection shall take place prior to the sale of a lease covering the area in which such activity was conducted.
(2)(i) Except as provided for in 30 CFR 250.106 and 251.14, no privileged or proprietary data or information will be transmitted to any affected State unless the lessee who provided the privileged or proprietary data or information agrees in writing to the transmittal of the data or information.
(ii) Except as provided for in 30 CFR 250.106 and 251.14, no privileged or proprietary data or information will be transmitted to any affected State unless the permittee and all persons to whom the permittee has sold the data or information under promise of confidentiality agree in writing to the transmittal of the data or information.
(3) Knowledge obtained by a State official who inspects data or information under paragraph (a)(1) or who receives data or information under paragraph (a)(2) of this section shall be subject to the requirements and limitations of the Freedom of Information Act (5 U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and Testimony), the Act (92 Stat. 629), the regulations contained in 30 CFR part 250 (Oil and Gas and Sulphur Operations in the Outer Continental Shelf), the regulations contained in 30 CFR part 251 (Geological and Geophysical Explorations of the Outer Continental Shelf), and the regulations contained in this part 252 (Outer Continental Shelf Oil and Gas Information Program).
(4) Prior to the transmittal of any privileged or proprietary data or information to any State, or the grant of access to a State official to such data or information, the Secretary shall enter into a written agreement with the Governor of the State in accordance with section 26(e) of the Act (43 U.S.C. 1352). In that agreement the State shall agree, as a condition precedent to receiving or being granted access to such data or information to: (i) Protect and maintain the confidentiality of privileged or proprietary data and information in accordance with the laws and regulations listed in paragraph (a)(3) of this section; (ii) waive the defenses as set forth in paragraph (b)(2) of this section; and (iii) hold the United States harmless from any violations of the agreement to protect the confidentiality of privileged or proprietary data or information by the State or its employees or contractors.
(b)(1) Whenever any employee of the Federal Government or of any State reveals in violation of the Act or of the provisions of the regulations implementing the Act, privileged or proprietary data or information obtained pursuant to the regulations in this chapter, the lessee or permittee who supplied such information to the Director or any other Federal official, and any person to whom such lessee or permittee has sold such data or information under the promise of confidentiality, may commence a civil action for damages in the appropriate district court of the United States against the Federal Government or such State, as the case may be. Any Federal or State employee who is found guilty of failure to comply with any of the requirements of this section shall be subject to the penalties described in section 24 of the Act (43 U.S.C. 1350).
(2) In any action commenced against the Federal Government or a State pursuant to paragraph (b)(1) of this section, the Federal Government or such State, as the case may be, may not raise as a defense any claim of sovereign immunity, or any claim that the employee who revealed the privileged or proprietary data or information which is the basis of such suit was acting outside the scope of the person's employment in revealing such data or information.
(c) If the Director finds that any State cannot or does not comply with the conditions described in the agreement entered into pursuant to paragraph (a)(4) of this section, the Director shall thereafter withhold transmittal and deny access for inspection of privileged or proprietary data or information to such State until the Director finds that such State can and will comply with those conditions.
33 U.S.C. 2701
At 63 FR 42711, Aug. 11, 1998, part 253 was added. This part contains information collection and recordkeeping requirements and will not become effective until approval has been given by the Office of Management and Budget.
This part establishes the requirements for demonstrating OSFR for covered offshore facilities (COFs) under Title I of the Oil Pollution Act of 1990 (OPA), as amended, 33 U.S.C. 2701
Terms used in this part have the following meaning:
(1) That includes any structure and all its components (including wells completed at the structure and the associated pipelines), equipment, pipeline, or device (other than a vessel or other than a pipeline or deepwater port licensed under the Deepwater Port Act of 1974 (33 U.S.C. 1501
(2) That is located:
(i) Seaward of the coastline; or
(ii) In any portion of a bay that is:
(A) Connected to the sea, either directly or through one or more other bays; and
(B) Depicted in whole or in part on any USGS map listed in the Appendix to this part, or on any map published by the USGS that is a successor to and covers all or part of the same area as a listed map. Where any portion of a bay is included on a listed map, this rule applies to the entire bay; and
(3) That has a worst case oil-spill discharge potential of more than 1,000 bbls of oil, or a lesser volume if the Director determines in writing that the oil-spill discharge risk justifies the requirement to demonstrate OSFR.
(1) Oil includes:
(i) Petroleum, fuel oil, sludge, oil refuse, and oil mixed with wastes other than dredged spoil;
(ii) Hydrocarbons produced at the wellhead in liquid form;
(iii) Gas condensate that has been separated from gas before pipeline injection.
(2) Oil does not include petroleum, including crude oil or any fraction thereof, which is specifically listed or designated as a hazardous substance under subparagraphs (A) through (F) of section 101(14) of the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) (42 U.S.C. 9601).
(1) For a COF that is a pipeline, responsible party means any person owning or operating the pipeline;
(2) For a COF that is not a pipeline, responsible party means either the lessee or permittee of the area in which the COF is located, or the holder of a right-of-use and easement granted under applicable state law or the OCSLA (43 U.S.C. 1301-1356) for the area in which the COF is located (if the holder is a different person than the lessee or permittee). A Federal agency, State, municipality, commission, or political subdivision of a state, or any interstate body that as owner transfers possession and right to use the property to another person by lease, assignment, or permit is not a responsible party; and
(3) For an abandoned COF, responsible party means any person who would have been a responsible party for the COF immediately before abandonment.
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part 253 under 44 U.S.C. 3501
(b) MMS collects the information to ensure that the designated applicant for a COF has the financial resources necessary to pay for cleanup and damages that could be caused by oil discharges from the COF. MMS uses the information to ensure compliance of offshore lessees, owners, and operators of covered facilities with OPA; to establish eligibility of designated applicants for OSFR certification (OSFRC); and to establish a reference source of
(c) An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
(a) This part applies to any COF on any lease or permit issued or on any RUE granted under the OCSLA or applicable state law.
(b) For a pipeline COF that extends onto land, this part applies to that portion of the pipeline lying seaward of the first accessible flow shut-off device on land.
(a) A designated applicant must demonstrate OSFR. A designated applicant may be a responsible party or another person authorized under this section. Each COF must have a single designated applicant.
(1) If there is more than one responsible party, those responsible parties must use Form MMS-1017 to select a designated applicant. The designated applicant must submit Form MMS-1016 and agree to demonstrate OSFR on behalf of all the responsible parties.
(2) If you are a designated applicant who is not a responsible party, you must agree to be liable for claims made under OPA jointly and severally with the responsible parties.
(b) The designated applicant for a COF on a lease must be either:
(1) A lessee; or
(2) The designated operator for the OCS lease under 30 CFR 250.143 or the unit operator designated under a Federally approved unit including the OCS lease. For a lease or unit not in the OCS, the operator designated under the lease or unit operating agreement for the lease may be the designated applicant only if the operator has agreed to be responsible for compliance with all the laws and regulations applicable to the lease or unit.
(c) The designated applicant for a COF on a permit must be the permittee.
(d) The designated applicant for a COF on a RUE must be the holder of the RUE or, if there is a pipeline on the RUE, the owner or operator of the pipeline.
(e) MMS may require the designated applicant for a lease, permit, or RUE to be a person other than a person identified in paragraphs (b) through (d) of this section if MMS determines that a person identified in paragraphs (b) through (d) cannot adequately demonstrate OSFR.
(f) If you are a responsible party and you fail to designate an applicant, then you must demonstrate OSFR under the requirements of this part.
You may submit to MMS a request for a determination of OSFR applicability. Address the request to the office identified in § 253.45. You must include in your request any information that will assist MMS in making the determination. MMS may require you to submit other information before making a determination of OSFR applicability.
(a) The following general parameters apply to the amount of OSFR that you must demonstrate:
(b) You must demonstrate OSFR in the amounts specified in this section:
(1) For a COF located wholly or partially in the OCS you must demonstrate OSFR in accordance with the following table:
(2) For a COF not located in the OCS you must demonstrate OSFR in accordance with the following table:
(3) The Director may determine that you must demonstrate an amount of OSFR greater than the amount in paragraphs (b)(1) and (2) of this section based on the relative operational, environmental, human health, and other risks that your COF poses. The Director may require an amount that is one or more levels higher than the amount indicated in paragraph (b)(1) or (2) of this section for your COF. The Director will not require an OSFR demonstration that exceeds $150 million.
(4) You must demonstrate OSFR in the lowest amount specified in the applicable table in paragraph (b)(1) or (b)(2) for a facility with a potential worst case oil-spill discharge of 1,000 bbls or less if the Director notifies you in writing that the demonstration is justified by the risks of the potential oil-spill discharge.
(a) To calculate the amount of OSFR you must demonstrate for a facility under § 253.13(b), you must use the worst case oil-spill discharge volume that you determined under whichever of the following regulations applies:
(1) 30 CFR Part 254—Response Plans for Facilities Located Seaward of the Coast Line, except that the volume of the worst case oil-spill discharge for a well must be four times the uncontrolled flow volume that you estimate for the first 24 hours.
(2) 40 CFR Part 112—Oil Pollution Prevention; or
(3) 49 CFR Part 194—Response Plans for Onshore Oil Pipelines.
(b) If you are a designated applicant and you choose to demonstrate $150 million in OSFR, you are not required to determine any worst case oil-spill discharge volumes, since that is the maximum amount of OSFR required under this part.
(a) You must maintain continuous OSFR coverage for all your leases, permits, and RUEs with COFs for which you are the designated applicant.
(b) You must ensure that new OSFR evidence is submitted before your current evidence lapses or is canceled and that coverage for your new COF is submitted before the COF goes into operation.
(c) If you use self-insurance to demonstrate OSFR and find that you no longer qualify to self-insure the required OSFR amount based upon your latest audited annual financial statements, then you must demonstrate OSFR using other methods acceptable to MMS by whichever of the following dates comes first:
(1) Sixty calendar days after you receive your latest audited annual financial statement; or
(2) The first calendar day of the 5th month after the close of your fiscal year.
(d) You may use a surety bond to demonstrate OSFR. If you find that your bonding company has lost its state license or has had its U.S. Treasury Department certification revoked, then you must replace the surety bond within 15 calendar days using a method of OSFR that is acceptable to MMS.
(e) You must notify MMS in writing within 15 calendar days after a change occurs that would prevent you from meeting your OSFR obligations (e.g., if you or your indemnitor petition for bankruptcy under Chapters 7 or 11 of Title 11, U.S.C.). You must take any action MMS directs to ensure an acceptable OSFR demonstration.
(f) If you deny payment of a claim presented to you under § 253.60, then you must give the claimant a written explanation for your denial.
As the designated applicant, you may satisfy your OSFR requirements by using one or a combination of the following methods to demonstrate OSFR:
(a) Self-insurance under §§ 253.21 through 253.28;
(b) Insurance under § 253.29;
(c) An indemnity under § 253.30;
(d) A surety bond under § 253.31; or
(e) An alternative method the Director approves under § 253.32.
(a) If you use self-insurance to satisfy all or part of your obligation to demonstrate OSFR, you must annually pass either a net worth test under § 253.25 or an unencumbered net asset test under § 253.28.
(b) To establish the amount of self-insurance allowed, you must submit evidence of your net worth under § 253.23 or evidence of your unencumbered assets under § 253.26.
(c) You must identify a U.S. agent for service of process.
(a) You must submit a complete Form MMS-1018 with each application to demonstrate OSFR using self-insurance.
(b) You must submit your application to renew OSFR using self-insurance by the first calendar day of the 5th month after the close of your fiscal year. You may submit to MMS your initial application to demonstrate OSFR using self-insurance at any time.
You must support your net worth evaluation with information contained in your previous fiscal year's audited annual financial statement.
(a) Audited annual financial statements must be in the form of:
(1) An annual report, prepared in accordance with the generally accepted accounting practices (GAAP) of the United States or other international accounting practices determined to be equivalent by MMS; or
(2) A Form 10-K or Form 20-F, prepared in accordance with Securities and Exchange Commission regulations.
(b) Audited annual financial statements must be submitted together with a letter signed by your treasurer highlighting:
(1) The State or the country of incorporation;
(2) The total amount of the stockholders’ equity as shown on the balance sheet;
(3) The net amount of the plant, property, and equipment shown on the balance sheet; and
(4) The net amount of the identifiable U.S. assets and the identifiable total assets in the auditor's notes to the financial statement (i.e., a geographic segmented business note).
(a) Your audited annual financial statements must be bound.
(b) Your audited annual financial statements must include the unqualified opinion of an independent accountant that states:
(1) The financial statements are free from material misstatement, and
(2) The audit was conducted in accordance with the generally accepted auditing standards (GAAS) of the United States, or other international auditing standards that MMS determines to be equivalent.
(c) The financial information you submit must be expressed in U.S. dollars. If this information was originally reported in another form of currency, you must convert it to U.S. dollars using the conversion factor that was effective on the last day of the fiscal year pertinent to your financial statements. You also must identify the source of the currency exchange rate.
(a) Divide the total amount of the stockholders’/owners’ equity listed on the balance sheet by ten.
(b) Divide the net amount of the identifiable U.S. assets by the net amount of the identifiable total assets.
(c) Multiply the net amount of plant, property, and equipment shown on the balance sheet by the number calculated under paragraph (b) of this section and divide the resultant product by ten.
(d) The smaller of the numbers calculated under paragraphs (a) or (c) of this section is the maximum allowable amount you may use to demonstrate OSFR under this method.
You must support your unencumbered assets evaluation with the information required by § 253.23(a) and a list of reserved, unencumbered, and unimpaired U.S. assets whose value will not be affected by an oil discharge from a COF. The assets must be plant, property, or equipment held for use. You must submit a letter signed by your treasurer:
(a) Identifying which assets are reserved;
(b) Certifying that the assets are unencumbered, including contingent encumbrances;
(c) Promising that the identified assets will not be sold, subjected to a security interest, or otherwise encumbered throughout the specified fiscal year; and
(d) Specifying:
(1) The State or the country of incorporation;
(2) The total amount of the stockholders’/owners’ equity listed on the balance sheet;
(3) The identification and location of the reserved U.S. assets; and
(4) The value of the reserved U.S. assets less accumulated depreciation and amortization, using the same valuation method used in your audited annual financial statement and expressed in U.S. dollars. The net value of the reserved assets must be at least two
Any audited annual financial statements that you submit must:
(a) Meet the standards in § 253.24; and
(b) Include a certification by the independent accountant who audited the financial statements that states:
(1) The value of the unencumbered assets is reasonable and uses the same valuation method used in your audited annual financial statements;
(2) Any existing encumbrances are noted;
(3) The assets are long-term assets held for use; and
(4) The valuation method used in the audited annual financial statements is for long-term assets held for use.
(a) Divide the total amount of the stockholders’/owners’ equity listed on the balance sheet by 4.
(b) Divide the value of the unencumbered U.S. assets by 2.
(c) The smaller number calculated under paragraphs (a) or (b) of this section is the maximum allowable amount you may use to demonstrate OSFR under this method.
(a) If you use insurance to satisfy all or part of your obligation to demonstrate OSFR, you may use only insurance certificates issued by insurers that have achieved a “Secure” rating for claims paying ability in their latest review by A.M. Best's Insurance Reports, Standard & Poor's Insurance Rating Services, or other equivalent rating made by a rating service acceptable to MMS.
(b) You must submit information about your insurers to MMS on a completed and unaltered Form MMS-1019. The information you submit must:
(1) Include all the information required by § 253.41 and
(2) Be executed on one original insurance certificate (i.e., Form MMS-1019) for each OSFR layer (see paragraph (c) of this section ), showing all participating insurers and their proportion (quota share) of this risk. The certificate must bear the original signatures of each insurer's underwriter or of their lead underwriters, underwriting managers, or delegated brokers, depending on who is authorized to bind the underwriter.
(3) For each insurance company on the insurance certificate, indicate the insurer's claims-paying-ability rating and the rating service that issued the rating.
(c) The insurance evidence you provide to MMS as OSFR evidence may be divided into layers, subject to the following restrictions:
(1) The total amount of OSFR evidence must equal the total amount you must demonstrate under § 253.13;
(2) No more than one insurance certificate may be used to cover each OSFR layer specified in § 253.13(b) (i.e., four layers for an OCS COF, and five layers for a non-OCS COF);
(3) You may use one insurance certificate to cover any number of consecutive OSFR layers;
(4) Each insurer's participation in the covered insurance risk must be on a proportional (quota share) basis, must be expressed as a percentage of a whole layer, and the certificate must not contain intermediate, horizontal layers;
(5) You may use an insurance deductible. If you use more than one insurance certificate, the deductible amount must apply only to the certificate that covers the base OSFR amount layer. To satisfy an insurance deductible, you may use only those methods that are acceptable as evidence of OSFR under this part; and
(6) You must identify a U.S. agent for service of process on each insurance certificate you submit to MMS. The agent may be different for each insurance certificate.
(d) You may submit to MMS a temporary insurance confirmation (fax binder) for each insurance certificate you use as OSFR evidence. Submit your fax binder on Form MMS-1019, and each form must include the signature of an underwriter for at least one
(a) You may use only one indemnity issued by only one indemnitor to satisfy all or part of your obligation to demonstrate OSFR.
(b) Your indemnitor must be your corporate parent or affiliate.
(c) Your indemnitor must complete a Form MMS-1018 and provide an indemnity that:
(1) Includes all the information required by § 253.41; and
(2) Does not exceed the amounts calculated using the net worth or unencumbered assets tests specified under §§ 253.21 through 253.28.
(d) You must submit your application to renew OSFR using an indemnity by the first calendar day of the 5th month after the close of your indemnitor's fiscal year. You may submit to MMS your initial application to demonstrate OSFR using an indemnity at any time.
(e) Your indemnitor must identify a U.S. agent for service of process.
(a) Each bonding company that issues a surety bond that you submit to MMS as OSFR evidence must:
(1) Be licensed to do business in the State in which the surety bond is executed;
(2) Be certified by the U.S. Treasury Department as an acceptable surety for Federal obligations and listed in the current Treasury Circular No. 570;
(3) Provide the surety bond on Form MMS-1020; and
(4) Be in compliance with applicable statutes regulating surety company participation in insurance-type risks.
(b) A surety bond that you submit as OSFR evidence must include all the information required by § 253.41.
The Director may accept other methods to demonstrate OSFR that provide equivalent assurance of timely satisfaction of claims. This may include pooling, letters of credit, pledges of treasury notes, or other comparable methods. Submit your proposal, together with all the supporting documents, to the Director at the address listed in § 253.45. The Director's decision whether to approve your alternative method to evidence OSFR is by this rule committed to the Director's sole discretion and is not subject to administrative appeal under 30 CFR part 290 or 43 CFR part 4.
(a) You must submit to MMS:
(1) A single demonstration of OSFR that covers all the COFs for which you are the designated applicant;
(2) A completed and unaltered Form MMS-1016;
(3) MMS forms that identify your COFs (Form MMS-1021, Form MMS-1022), and the methods you will use to demonstrate OSFR (Form MMS-1018, Form MMS-1019, Form MMS-1020). Forms are available from the address listed in § 253.45;
(4) Any insurance certificates, indemnities, and surety bonds used as OSFR evidence for the COFs for which you are the designated applicant;
(5) A completed Form MMS-1017 for each responsible party, unless you are the only responsible party for the COFs covered by your OSFR demonstration; and
(6) Other financial instruments and information the Director requires to support your OSFR demonstration under § 253.32.
(b) Each MMS form you submit to MMS as part of your OSFR demonstration must be signed. You also must attach to Form MMS-1016 proof of your authority to sign.
(a) Each instrument you submit as OSFR evidence must specify:
(1) The effective date, and except for a surety bond, the expiration date;
(2) That termination of the instrument will not affect the liability of the
(3) That the instrument will remain in force until the termination date or until the earlier of:
(i) Thirty calendar days after MMS and the designated applicant receive from the instrument issuer a notification of intent to cancel; or
(ii) MMS receives from the designated applicant other acceptable OSFR evidence; or
(iii) All the COFs to which the instrument applies are permanently abandoned in compliance with 30 CFR part 250 or equivalent State requirements;
(4) That the instrument issuer agrees to direct action for claims made under OPA up to the guaranty amount, subject to the defenses in paragraph (a)(6) of this section and following the procedures in § 253.60 of this part;
(5) An agent in the United States for service of process; and
(6) That the instrument issuer will not use any defenses against a claim made under OPA except:
(i) The rights and defenses that would be available to a designated applicant or responsible party for whom the guaranty was provided; and
(ii) The incident (i.e., oil-spill discharge or a substantial threat of the discharge of oil) leading to the claim for removal costs or damages was caused by willful misconduct of a responsible party for whom the designated applicant demonstrated OSFR.
(b) You may not change, omit, or add limitations or exceptions to the terms and conditions in an MMS form that you submit as part of your OSFR demonstration. If you attempt to do this, MMS will disregard the changes, omissions, additions, limitations, or exceptions and by operation of this rule MMS will consider the form to contain all the terms and conditions included on the original MMS form.
(a) If you want to add a COF that is not identified in your current OSFR demonstration, you must submit to MMS a completed Form MMS-1022. If applicable, you also must submit any additional indemnities, surety bonds, insurance certificates, or other instruments required to extend the coverage of your original OSFR demonstration to the COFs to be added. You do not need to resubmit previously accepted audited annual financial statements for the current fiscal year.
(b) If you want to drop a COF identified in your current OSFR demonstration, you must submit to MMS a completed Form MMS-1022. You must continue to demonstrate OSFR for the COF until MMS approves OSFR evidence for the COF from another designated applicant, or OSFR is no longer required (e.g., until a well that is a COF is properly plugged and abandoned).
(a) MMS will notify you in writing when we approve your OSFR demonstration. If we find that you have not submitted all the information needed to demonstrate OSFR, we may require you to provide additional information before we determine whether your OSFR evidence is acceptable.
(b) Except in the case of self-insurance or an indemnity, MMS acceptance of OSFR evidence is valid until the surety bond, insurance certificate, or other accepted OSFR instrument expires or is canceled. In the case of self-insurance or indemnity, acceptance is valid until the first day of the 5th month after the close of your or your indemnitor's current fiscal year.
If you are the designated applicant for one or more COFs covered by a Certificate of Financial Responsibility (CFR) issued under 33 CFR part 135 that expires after October 13, 1998, you must submit to MMS your evidence of OSFR for all your COFs no later than the earliest date that an existing CFR for any of your COFs expires. All other designated applicants must submit to MMS evidence of OSFR for their COFs no later than April 8, 1999.
Address all correspondence and required submissions related to this part to: U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico Region, Oil Spill Financial Responsibility Program, 1201 Elmwood Park Boulevard, New Orleans, Louisiana 70123.
(a) If MMS determines that any OSFR evidence you submit fails to comply with the requirements of this part, we may not accept it. If we do not accept your OSFR evidence, then we will send you a written notification stating:
(1) That your evidence is not acceptable;
(2) Why your evidence is unacceptable; and
(3) The amount of time you are allowed to submit acceptable evidence without being subject to civil penalty under § 253.51.
(b) MMS may immediately and without prior notice invalidate your OSFR demonstration if you:
(1) Are no longer eligible to be the designated applicant for a COF included in your demonstration; or
(2) Permit the cancellation or termination of the insurance policy, surety bond, or indemnity upon which the continued validity of the demonstration is based.
(c) If MMS determines you are not complying with the requirements of this part for any reason other than paragraph (b) of this section, we will notify you of our intent to invalidate your OSFR demonstration and specify the corrective action needed. Unless you take the corrective action MMS specifies within 15 calendar days from the date you receive such a notice, we will invalidate your OSFR demonstration.
(a) If you fail to comply with the financial responsibility requirements of OPA at 33 U.S.C. 2716 or with the requirements of this part, then you may be liable for a civil penalty of up to $25,000 per COF per day of violation (that is, each day a COF is operated without acceptable evidence of OSFR).
(b) MMS will determine the date of a noncompliance. MMS will assess penalties in accordance with an OSFR penalty schedule using the procedures found at 30 CFR part 250, subpart N. You may obtain a copy of the penalty schedule from MMS at the address in § 253.45.
(c) MMS may assess a civil penalty against you that is greater or less than the amount in the penalty schedule after taking into account the factors in section 4303(a) of OPA (33 U.S.C. 2716a).
(d) If you fail to correct a deficiency in the OSFR evidence for a COF, then the Director may suspend operation of a COF in the OCS under 30 CFR 250.170 or seek judicial relief, including an order suspending the operation of any COF.
(a) If you are a claimant, you must present your claim first to the designated applicant for the COF that is the source of the incident resulting in your claim. If, however, the designated applicant has filed a petition for bankruptcy under 11 U.S.C. chapter 7 or 11, you may present your claim first to any of the designated applicant's guarantors.
(b) If the claim you present to the designated applicant or guarantor is denied or not paid within 90 days after you first present it or advertising begins, whichever is later, then you may seek any of the following remedies that apply:
(c) If no one has resolved your claim to your satisfaction using the remedy that you elected under paragraph (b) of this section, then you may pursue another available remedy, unless the Fund has denied your claim or a court of competent jurisdiction has ruled against your claim. You may not pursue more than one remedy at a time.
(d) You may ask MMS to assist you in determining whether a guarantor may be liable for your claim. Send your request for assistance to the address listed in § 253.45. You must include any information you have regarding the existence or identity of possible guarantors.
(a) If you are a guarantor, then you are subject to direct action for any claim asserted by:
(1) The United States for any compensation paid by the Fund under OPA, including compensation claim processing costs; and
(2) A claimant other than the United States if the designated applicant has:
(i) Denied or failed to pay a claim because of being insolvent; or
(ii) Filed a petition in bankruptcy under 11 U.S.C. chapters 7 or 11.
(b) If you participate in an insurance guaranty for a COF incident (i.e., oil-spill discharge or substantial threat of the discharge of oil) that is subject to claims under this part, then your maximum, aggregate liability for those claims is equal to your quota share of the insurance guaranty.
If you are a designated applicant, and you receive a claim for removal costs and damages, then within 15 calendar days of receipt of a claim you must notify:
(a) Your guarantors; and
(b) The responsible parties for whom you are acting as the designated applicant.
33 U.S.C. 1321
(a) If you are the owner or operator of an oil handling, storage, or transportation facility, and it is located seaward of the coast line, you must submit a spill-response plan to MMS for approval. Your spill-response plan must demonstrate that you can respond quickly and effectively whenever oil is discharged from your facility. Refer to § 254.6 for the definitions of “oil,” “facility,” and “coast line” if you have any doubts about whether to submit a plan.
(b) You must maintain a current response plan for an abandoned facility until you physically remove or dismantle the facility or until the Regional Supervisor notifies you in writing that a plan is no longer required.
(c) Owners or operators of offshore pipelines carrying essentially dry gas do not need to submit a plan. You must, however, submit a plan for a pipeline that carries:
(1) Oil;
(2) Condensate that has been injected into the pipeline; or
(3) Gas and naturally occurring condensate.
(d) If you are in doubt as to whether you must submit a plan for an offshore facility or pipeline, you should check with the Regional Supervisor.
(e) If your facility is located landward of the coast line, but you believe your facility is sufficiently similar to OCS facilities that it should be regulated by MMS, you may contact the Regional Supervisor, offer to accept MMS jurisdiction over your facility, and request that MMS seek from the agency with jurisdiction over your facility a relinquishment of that jurisdiction.
(a) You must submit, and MMS must approve, a response plan that covers each facility located seaward of the coast line before you may use that facility. To continue operations, you must operate the facility in compliance with the plan.
(b) Despite the provisions of paragraph (a) of this section, you may operate your facility after you submit your plan while MMS reviews it for approval. To operate a facility without an approved plan, you must certify in writing to the Regional Supervisor that you have the capability to respond, to the maximum extent practicable, to a worst case discharge or a substantial threat of such a discharge. The certification must show that you have ensured by contract, or other means approved by the Regional Supervisor, the availability of private personnel and equipment necessary to respond to the discharge. Verification from the organization(s) providing the personnel and equipment must accompany the certification. MMS will not allow you to operate a facility for more than 2 years without an approved plan.
(c) If you have a plan that MMS already approved, you are not required to immediately rewrite the plan to comply with this part. You must, however, submit the information this regulation requires when submitting your first plan revision (see § 254.30) after the effective date of this rule. The Regional Supervisor may extend this deadline upon request.
(a) Your response plan may be for a single lease or facility or a group of
(b) Regional Response Plans must address all the elements required for a response plan in Subpart B,
(c) When developing a Regional Response Plan, you may group leases or facilities subject to the approval of the Regional Supervisor for the purposes of:
(1) Calculating response times;
(2) Determining quantities of response equipment;
(3) Conducting oil-spill trajectory analyses;
(4) Determining worst case discharge scenarios; and
(5) Identifying areas of special economic and environmental importance that may be impacted and the strategies for their protection.
(d) The Regional Supervisor may specify how to address the elements of a Regional Response Plan. The Regional Supervisor also may require that Regional Response Plans contain additional information if necessary for compliance with appropriate laws and regulations.
You may reference information contained in other readily accessible documents in your response plan. Examples of documents that you may reference are the National Contingency Plan (NCP), Area Contingency Plan (ACP), MMS environmental documents, and Oil Spill Removal Organization (OSRO) documents that are readily accessible to the Regional Supervisor. You must ensure that the Regional Supervisor possesses or is provided with copies of all OSRO documents you reference. You should contact the Regional Supervisor if you want to know whether a reference is acceptable.
(a) The response plan must provide for response to an oil spill from the facility. You must immediately carry out the provisions of the plan whenever there is a release of oil from the facility. You must also carry out the training, equipment testing, and periodic drills described in the plan, and these measures must be sufficient to ensure the safety of the facility and to mitigate or prevent a discharge or a substantial threat of a discharge.
(b) The plan must be consistent with the National Contingency Plan and the appropriate Area Contingency Plan(s).
(c) Nothing in this part relieves you from taking all appropriate actions necessary to immediately abate the source of a spill and remove any spills of oil.
(d) In addition to the requirements listed in this part, you must provide any other information the Regional Supervisor requires for compliance with appropriate laws and regulations.
For the purposes of this part:
You must submit the number of copies of your response plan that the appropriate MMS regional office requires. If you prefer to use improved information technology such as electronic filing to submit your plan, ask the Regional Supervisor for further guidance.
(a) Send plans for facilities located seaward of the coast line of Alaska to: Minerals Management Service, Regional Supervisor, Field Operations, Alaska OCS Region, 949 East 36th Avenue, Anchorage, AK 99508-4302.
(b) Send plans for facilities in the Gulf of Mexico or Atlantic Ocean to: Minerals Management Service, Regional Supervisor, Field Operations, Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard, New Orleans, LA 70123-2394.
(c) Send plans for facilities in the Pacific Ocean (except seaward of the coast line of Alaska) to: Minerals Management Service, Regional Supervisor, Office of Development Operations and Safety, Pacific OCS Region, 770 Paseo Camarillo, Camarillo, CA 93010-6064.
See 30 CFR part 290 for instructions on how to appeal any order or decision that we issue under this part.
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501
(b) MMS collects this information to ensure that the owner or operator of an offshore facility is prepared to respond to an oil spill. MMS uses the information to verify compliance with the mandates of the Oil Pollution Act of 1990 (OPA). The requirement to submit this information is mandatory. No confidential or proprietary information is collected.
(c) An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
This subpart describes the requirements for preparing spill-response plans for facilities located on the OCS.
(a) You must divide your response plan for OCS facilities into the sections specified in paragraph (b) and explained in the other sections of this subpart. The plan must have an easily found marker identifying each section. You may use an alternate format if you include a cross-reference table to identify the location of required sections. You may use alternate contents if you can demonstrate to the Regional Supervisor that they provide for equal or greater levels of preparedness.
(b) Your plan must include:
(1) Introduction and plan contents.
(2) Emergency response action plan.
(3) Appendices:
(i) Equipment inventory.
(ii) Contractual agreements.
(iii) Worst case discharge scenario.
(iv) Dispersant use plan.
(v) In situ burning plan.
(vi) Training and drills.
The “Introduction and plan contents” section must provide:
(a) Identification of the facility the plan covers, including its location and type;
(b) A table of contents;
(c) A record of changes made to the plan; and
(d) A cross-reference table, if needed, because you are using an alternate format for your plan.
The “Emergency response action plan”section is the core of the response plan. Put information in easy-to-use formats such as flow charts or tables where appropriate. This section must include:
(a) Designation, by name or position, of a trained qualified individual (QI) who has full authority to implement removal actions and ensure immediate notification of appropriate Federal officials and response personnel.
(b) Designation, by name or position, of a trained spill management team available on a 24-hour basis. The team must include a trained spill-response coordinator and alternate(s) who have the responsibility and authority to direct and coordinate response operations on your behalf. You must describe the team's organizational structure as well as the responsibilities and authorities of each position on the spill management team.
(c) Description of a spill-response operating team. Team members must be trained and available on a 24-hour basis to deploy and operate spill-response equipment. They must be able to respond within a reasonable minimum specified time. You must include the number and types of personnel available from each identified labor source.
(d) A planned location for a spill-response operations center and provisions for primary and alternate communications systems available for use in coordinating and directing spill-response operations. You must provide telephone numbers for the response operations center. You also must provide any facsimile numbers and primary and secondary radio frequencies that will be used.
(e) A listing of the types and characteristics of the oil handled, stored, or transported at the facility.
(f) Procedures for the early detection of a spill.
(g) Identification of procedures you will follow in the event of a spill or a substantial threat of a spill. The procedures should show appropriate response levels for differing spill sizes including those resulting from a fire or explosion. These will include, as appropriate:
(1) Your procedures for spill notification. The plan must provide for the use of the oil spill reporting forms included in the Area Contingency Plan or an equivalent reporting form.
(i) Your procedures must include a current list which identifies the following by name or position, corporate
(A) The qualified individual;
(B) The spill-response coordinator and alternate(s); and
(C) Other spill-response management team members.
(ii) You must also provide names, telephone numbers, and addresses for the following:
(A) OSRO's that the plan cites;
(B) Federal, State, and local regulatory agencies that you must consult to obtain site specific environmental information; and
(C) Federal, State, and local regulatory agencies that you must notify when an oil spill occurs.
(2) Your methods to monitor and predict spill movement;
(3) Your methods to identify and prioritize the beaches, waterfowl, other marine and shoreline resources, and areas of special economic and environmental importance;
(4) Your methods to protect beaches, waterfowl, other marine and shoreline resources, and areas of special economic or environmental importance;
(5) Your methods to ensure that containment and recovery equipment as well as the response personnel are mobilized and deployed at the spill site;
(6) Your methods to ensure that devices for the storage of recovered oil are sufficient to allow containment and recovery operations to continue without interruption;
(7) Your procedures to remove oil and oiled debris from shallow waters and along shorelines and rehabilitating waterfowl which become oiled;
(8) Your procedures to store, transfer, and dispose of recovered oil and oil-contaminated materials and to ensure that all disposal is in accordance with Federal, State, and local requirements; and
(9) Your methods to implement your dispersant use plan and your in situ burning plan.
Your “Equipment inventory appendix” must include:
(a) An inventory of spill-response materials and supplies, services, equipment, and response vessels available locally and regionally. You must identify each supplier and provide their locations and telephone numbers.
(b) A description of the procedures for inspecting and maintaining spill-response equipment in accordance with § 254.43.
Your “Contractual agreements” appendix must furnish proof of any contracts or membership agreements with OSRO's, cooperatives, spill-response service providers, or spill management team members who are not your employees that you cite in the plan. To provide this proof, submit copies of the contracts or membership agreements or certify that contracts or membership agreements are in effect. The contract or membership agreement must include provisions for ensuring the availability of the personnel and/or equipment on a 24-hour-per-day basis.
The discussion of your worst case discharge scenario must include all of the following elements:
(a) The volume of your worst case discharge scenario determined using the criteria in § 254.47. Provide any assumptions made and the supporting calculations used to determine this volume.
(b) An appropriate trajectory analysis specific to the area in which the facility is located. The analysis must identify onshore and offshore areas that a discharge potentially could affect. The trajectory analysis chosen must reflect the maximum distance from the facility that oil could move in a time period that it reasonably could be expected to persist in the environment.
(c) A list of the resources of special economic or environmental importance that potentially could be impacted in the areas identified by your trajectory
(d) A discussion of your response to your worst case discharge scenario in adverse weather conditions. This discussion must include:
(1) A description of the response equipment that you will use to contain and recover the discharge to the maximum extent practicable. This description must include the types, location(s) and owner, quantity, and capabilities of the equipment. You also must include the effective daily recovery capacities, where applicable. You must calculate the effective daily recovery capacities using the methods described in § 254.44. For operations at a drilling or production facility, your scenario must show how you will cope with the initial spill volume upon arrival at the scene and then support operations for a blowout lasting 30 days.
(2) A description of the personnel, materials, and support vessels that would be necessary to ensure that the identified response equipment is deployed and operated promptly and effectively. Your description must include the location and owner of these resources as well as the quantities and types (if applicable);
(3) A description of your oil storage, transfer, and disposal equipment. Your description must include the types, location and owner, quantity, and capacities of the equipment; and
(4) An estimation of the individual times needed for:
(i) Procurement of the identified containment, recovery, and storage equipment;
(ii) Procurement of equipment transportation vessel(s);
(iii) Procurement of personnel to load and operate the equipment;
(iv) Equipment loadout (transfer of equipment to transportation vessel(s));
(v) Travel to the deployment site (including any time required for travel from an equipment storage area); and
(vi) Equipment deployment.
(e) In preparing the discussion required by paragraph (d) of this section, you must:
(1) Ensure that the response equipment, materials, support vessels, and strategies listed are suitable, within the limits of current technology, for the range of environmental conditions anticipated at your facility; and
(2) Use standardized, defined terms to describe the range of environmental conditions anticipated and the capabilities of response equipment. Examples of acceptable terms include those defined in American Society for Testing of Materials (ASTM) publication F625-94,
Your dispersant use plan must be consistent with the National Contingency Plan Product Schedule and other provisions of the National Contingency Plan and the appropriate Area Contingency Plan(s). The plan must include:
(a) An inventory and a location of the dispersants and other chemical or biological products which you might use on the oils handled, stored, or transported at the facility;
(b) A summary of toxicity data for these products;
(c) A description and a location of any application equipment required as well as an estimate of the time to commence application after approval is obtained;
(d) A discussion of the application procedures;
(e) A discussion of the conditions under which product use may be requested; and
(f) An outline of the procedures you must follow in obtaining approval for product use.
Your in situ burning plan must be consistent with any guidelines authorized by the National Contingency Plan and the appropriate Area Contingency
(a) A description of the in situ burn equipment including its availability, location, and owner;
(b) A discussion of your in situ burning procedures, including provisions for ignition of an oil spill;
(c) A discussion of environmental effects of an in situ burn;
(d) Your guidelines for well control and safety of personnel and property;
(e) A discussion of the circumstances in which in situ burning may be appropriate;
(f) Your guidelines for making the decision to ignite; and
(g) An outline of the procedures you must follow to obtain approval for an in situ burn.
Your “Training and drills” appendix must:
(a) Identify and include the dates of the training provided to members of the spill-response management team and the qualified individual. The types of training given to the members of the spill-response operating team also must be described. The training requirements for your spill management team and your spill-response operating team are specified in § 254.41. You must designate a location where you keep course completion certificates or attendance records for this training.
(b) Describe in detail your plans for satisfying the exercise requirements of § 254.42. You must designate a location where you keep the records of these exercises.
(a) You must review your response plan at least every 2 years and submit all resulting modifications to the Regional Supervisor. If this review does not result in modifications, you must inform the Regional Supervisor in writing that there are no changes.
(b) You must submit revisions to your plan for approval within 15 days whenever:
(1) A change occurs which significantly reduces your response capabilities;
(2) A significant change occurs in the worst case discharge scenario or in the type of oil being handled, stored, or transported at the facility;
(3) There is a change in the name(s) or capabilities of the oil spill removal organizations cited in the plan; or
(4) There is a significant change to the Area Contingency Plan(s).
(c) The Regional Supervisor may require that you resubmit your plan if the plan has become outdated or if numerous revisions have made its use difficult.
(d) The Regional Supervisor will periodically review the equipment inventories of OSRO's to ensure that sufficient spill removal equipment is available to meet the cumulative needs of the owners and operators who cite these organizations in their plans.
(e) The Regional Supervisor may require you to revise your plan if significant inadequacies are indicated by:
(1) Periodic reviews (described in paragraph (d) of this section);
(2) Information obtained during drills or actual spill responses; or
(3) Other relevant information the Regional Supervisor obtained.
You must make all records of services, personnel, and equipment provided by OSRO's or cooperatives available to any authorized MMS representative upon request.
(a) You must ensure that the members of your spill-response operating team who are responsible for operating response equipment attend hands-on training classes at least annually. This training must include the deployment and operation of the response equipment they will use. Those responsible for supervising the team must be trained annually in directing the deployment and use of the response equipment.
(b) You must ensure that the spill-response management team, including the spill-response coordinator and alternates, receives annual training. This training must include instruction on:
(1) Locations, intended use, deployment strategies, and the operational and logistical requirements of response equipment;
(2) Spill reporting procedures;
(3) Oil-spill trajectory analysis and predicting spill movement; and
(4) Any other responsibilities the spill management team may have.
(c) You must ensure that the qualified individual is sufficiently trained to perform his or her duties.
(d) You must keep all training certificates and training attendance records at the location designated in your response plan for at least 2 years. They must be made available to any authorized MMS representative upon request.
(a) You must exercise your entire response plan at least once every 3 years (triennial exercise). You may satisfy this requirement by conducting separate exercises for individual parts of the plan over the 3-year period; you do not have to exercise your entire response plan at one time.
(b) In satisfying the triennial exercise requirement, you must, at a minimum, conduct:
(1) An annual spill management team tabletop exercise. The exercise must test the spill management team's organization, communication, and decisionmaking in managing a response. You must not reveal the spill scenario to team members before the exercise starts.
(2) An annual deployment exercise of response equipment identified in your plan that is staged at onshore locations. You must deploy and operate each type of equipment in each triennial period. However, it is not necessary to deploy and operate each individual piece of equipment.
(3) An annual notification exercise for each facility that is manned on a 24- hour basis. The exercise must test the ability of facility personnel to communicate pertinent information in a timely manner to the qualified individual.
(4) A semiannual deployment exercise of any response equipment which the MMS Regional Supervisor requires an owner or operator to maintain at the facility or on dedicated vessels. You must deploy and operate each type of this equipment at least once each year. Each type need not be deployed and operated at each exercise.
(c) During your exercises, you must simulate conditions in the area of operations, including seasonal weather variations, to the extent practicable. The exercises must cover a range of scenarios over the 3-year exercise period, simulating responses to large continuous spills, spills of short duration and limited volume, and your worst case discharge scenario.
(d) MMS will recognize and give credit for any documented exercise conducted that satisfies some part of the required triennial exercise. You will receive this credit whether the owner or operator, an OSRO, or a Government regulatory agency initiates the exercise. MMS will give you credit for an actual spill response if you evaluate the response and generate a proper record. Exercise documentation should include the following information:
(1) Type of exercise;
(2) Date and time of the exercise;
(3) Description of the exercise;
(4) Objectives met; and
(5) Lessons learned.
(e) All records of spill-response exercises must be maintained for the complete 3-year exercise cycle. Records should be maintained at the facility or at a corporate location designated in the plan. Records showing that OSRO's and oil spill removal cooperatives have deployed each type of equipment also must be maintained for the 3-year cycle.
(f) You must inform the Regional Supervisor of the date of any exercise required by paragraph (b)(1), (2), or (4) of this section at least 30 days before the exercise. This will allow MMS personnel the opportunity to witness any exercises.
(g) The Regional Supervisor periodically will initiate unannounced drills to test the spill response preparedness of owners and operators.
(h) The Regional Supervisor may require changes in the frequency or location of the required exercises, equipment to be deployed and operated, or deployment procedures or strategies. The Regional Supervisor may evaluate the results of the exercises and advise the owner or operator of any needed changes in response equipment, procedures, or strategies.
(i) Compliance with the National Preparedness for Response Exercise Program (PREP) Guidelines will satisfy the exercise requirements of this section. Copies of the PREP document may be obtained from the Regional Supervisor.
(a) You must ensure that the response equipment listed in your response plan is inspected at least monthly and is maintained, as necessary, to ensure optimal performance.
(b) You must ensure that records of the inspections and the maintenance activities are kept for at least 2 years and are made available to any authorized MMS representative upon request.
(a) You are required by § 254.26(d)(1) to calculate the effective daily recovery capacity of the response equipment identified in your response plan that you would use to contain and recover your worst case discharge. You must calculate the effective daily recovery capacity of the equipment by multiplying the manufacturer's rated throughput capacity over a 24-hour period by 20 percent. This 20 percent efficiency factor takes into account the limitations of the recovery operations due to available daylight, sea state, temperature, viscosity, and emulsification of the oil being recovered. You must use this calculated rate to determine if you have sufficient recovery capacity to respond to your worst case discharge scenario.
(b) If you want to use a different efficiency factor for specific oil recovery devices, you must submit evidence to substantiate that efficiency factor. Adequate evidence includes verified performance data measured during actual spills or test data gathered according to the provisions of § 254.45 (b) and (c).
(a) The Regional Supervisor may require performance testing of any spill-response equipment listed in your response plan to verify its capabilities if the equipment:
(1) Has been modified;
(2) Has been damaged and repaired; or
(3) Has a claimed effective daily recovery capacity that is inconsistent with data otherwise available to MMS.
(b) You must conduct any required performance testing of booms in accordance with MMS-approved test criteria. You may use the document “Test Protocol for the Evaluation of Oil-Spill Containment Booms,” available from MMS, for guidance. Performance testing of skimmers also must be conducted in accordance with MMS approved test criteria. You may use the document “Suggested Test Protocol for the Evaluation of Oil Spill Skimmers for the OCS,” available from MMS, for guidance.
(c) You are responsible for any required testing of equipment performance and for the accuracy of the information submitted.
(a) You must immediately notify the National Response Center (1-800-424-8802) if you observe:
(1) An oil spill from your facility;
(2) An oil spill from another offshore facility; or
(3) An offshore spill of unknown origin.
(b) In the event of a spill of 1 barrel or more from your facility, you must orally notify the Regional Supervisor without delay. You also must report spills from your facility of unknown size but thought to be 1 barrel or more.
(1) If a spill from your facility not originally reported to the Regional Supervisor is subsequently found to be 1 barrel or more, you must then report it without delay.
(2) You must file a written followup report for any spill from your facility
(c) If you observe a spill resulting from operations at another offshore facility, you must immediately notify the responsible party and the Regional Supervisor.
You must calculate the volume of oil of your worst case discharge scenario as follows:
(a) For an oil production platform facility, the size of your worst case discharge scenario is the sum of the following:
(1) The maximum capacity of all oil storage tanks and flow lines on the facility. Flow line volume may be estimated; and
(2) The volume of oil calculated to leak from a break in any pipelines connected to the facility considering shutdown time, the effect of hydrostatic pressure, gravity, frictional wall forces and other factors; and
(3) The daily production volume from an uncontrolled blowout of the highest capacity well associated with the facility. In determining the daily discharge rate, you must consider reservoir characteristics, casing/production tubing sizes, and historical production and reservoir pressure data. Your scenario must discuss how to respond to this well flowing for 30 days as required by § 254.26(d)(1).
(b) For exploratory or development drilling operations, the size of your worst case discharge scenario is the daily volume possible from an uncontrolled blowout. In determining the daily discharge rate, you must consider any known reservoir characteristics. If reservoir characteristics are unknown, you must consider the characteristics of any analog reservoirs from the area and give an explanation for the selection of the reservoir(s) used. Your scenario must discuss how to respond to this well flowing for 30 days as required by § 254.26(d)(1).
(c) For a pipeline facility, the size of your worst case discharge scenario is the volume possible from a pipeline break. You must calculate this volume as follows:
(1) Add the pipeline system leak detection time to the shutdown response time.
(2) Multiply the time calculated in paragraph (c)(1) of this section by the highest measured oil flow rate over the preceding 12-month period. For new pipelines, you should use the predicted oil flow rate in the calculation.
(3) Add to the volume calculated in paragraph (c)(2) of this section the total volume of oil that would leak from the pipeline after it is shut in. Calculate this volume by taking into account the effects of hydrostatic pressure, gravity, frictional wall forces, length of pipeline segment, tie-ins with other pipelines, and other factors.
(d) If your facility which stores, handles, transfers, processes, or transports oil does not fall into the categories listed in paragraph (a), (b), or (c) of this section, contact the Regional Supervisor for instructions on the calculation of the volume of your worst case discharge scenario.
Owners or operators of facilities located in State waters seaward of the coast line must submit a spill-response plan to MMS for approval. You may choose one of three methods to comply with this requirement. The three methods are described in §§ 254.51, 254.52, and 254.53.
You may modify an existing response plan covering a lease or facility on the OCS to include a lease or facility in State waters located seaward of the coast line. Since this plan would cover more than one lease or facility, it would be considered a Regional Response Plan. You should refer to § 254.3 and contact the appropriate regional MMS office if you have any questions on how to prepare this Regional Response Plan.
You may develop a response plan following the requirements for plans for OCS facilities found in subpart B of this part.
(a) You may submit a response plan to MMS for approval that you developed in accordance with the laws or regulations of the appropriate State. The plan must contain all the elements the State and OPA require and must:
(1) Be consistent with the requirements of the National Contingency Plan and appropriate Area Contingency Plan(s).
(2) Identify a qualified individual and require immediate communication between that person and appropriate Federal officials and response personnel if there is a spill.
(3) Identify any private personnel and equipment necessary to remove, to the maximum extent practicable, a worst case discharge as defined in § 254.47. The plan must provide proof of contractual services or other evidence of a contractual agreement with any OSRO's or spill management team members who are not employees of the owner or operator.
(4) Describe the training, equipment testing, periodic unannounced drills, and response actions of personnel at the facility. These must ensure both the safety of the facility and the mitigation or prevention of a discharge or the substantial threat of a discharge.
(5) Describe the procedures you will use to periodically update and resubmit the plan for approval of each significant change.
(b) Your plan developed under State requirements also must include the following information:
(1) A list of the facilities and leases the plan covers and a map showing their location;
(2) A list of the types of oil handled, stored, or transported at the facility;
(3) Name and address of the State agency to whom the plan was submitted;
(4) Date you submitted the plan to the State;
(5) If the plan received formal approval, the name of the approving organization, the date of approval, and a copy of the State agency's approval letter if one was issued; and
(6) Identification of any regulations or standards used in preparing the plan.
In addition to your response plan, you must submit to the Regional Supervisor a description of the steps you are taking to prevent spills of oil or mitigate a substantial threat of such a discharge. You must identify all State or Federal safety or pollution prevention requirements that apply to the prevention of oil spills from your facility, and demonstrate your compliance with these requirements. You also should include a description of industry safety and pollution prevention standards your facility meets. The Regional Supervisor may prescribe additional equipment or procedures for spill prevention if it is determined that your efforts to prevent spills do not reflect good industry practices.
43 U.S.C. 1331
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501
(b) MMS collects this information to determine if the applicant filing for a lease on the Outer Continental Shelf is
(c) An agency may not conduct or sponsor, and a person is not required to respond to a collection of information unless it displays a currently valid OMB control number.
(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.
The purpose of the regulations in this part is to establish the procedures under which the Secretary of the Interior (Secretary) will exercise the authority to administer a leasing program for oil, gas and sulphur. The procedures under which the Secretary will exercise the authority to administer a program to grant rights-of-way, rights-of-use and easements are addressed in other parts.
The management of Outer Continental Shelf resources is to be conducted in accordance with the findings, purposes and policy directions provided by the Outer Continental Shelf Lands Act Amendments of 1978 (43 U.S.C. 1332, 1801, 1802), and other Executive, legislative, judicial and Departmental guidance. The Secretary of the Interior shall consider available environmental information in making decisions affecting Outer Continental Shelf resources.
The outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. 1331
As used in this part, the term:
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(1) The laws of which are declared, pursuant to section 4(a)(2) of the Act, to be the law of the United States for the portion of the Outer Continental Shelf on which such activity is, or is proposed to be conducted;
(2) Which is, or is proposed to be, directly connected by transportation facilities to any artificial island or structure referred to in section 4(a)(1) of the Act;
(3) Which is receiving, or in accordance with the proposed activity will receive, oil for processing, refining, or transshipment which was extracted from the Outer Continental Shelf and transported directly to such State by means of vessels or by a combination of means including vessels;
(4) Which is designated by the Secretary as a State in which there is a substantial probability of significant impact on or damage to the coastal, marine, or human environment, or a State in which there will be significant changes in the social, governmental, or economic infrastructure, resulting from the exploration, development, and production of oil and gas anywhere on the Outer Continental Shelf; or
(5) In which the Secretary finds that because of such activity there is, or will be, a significant risk of serious damage, due to factors such as prevailing winds and currents, to the marine or coastal environment in the event of any oilspill, blowout, or release of oil or gas from vessels, pipelines, or other transshipment facilities;
(h)
(i)
(j)
(k)
(l)
(a) For Minerals Management Service regulations governing exploration, development and production on leases, see 30 CFR parts 250 and 270.
(b) For MMS regulations governing the appeal of an order or decision issued under the regulations in this part, see 30 CFR part 290.
(c) For multiple use conflicts, see the Environmental Protection Agency listing of ocean dumping sites—40 CFR part 228.
(d) For related National Oceanic and Atmospheric Administration programs see:
(1) Marine sanctuary regulations, 15 CFR part 922;
(2) Fishermen's Contingency Fund, 50 CFR part 296;
(3) Coastal Energy Impact Program, 15 CFR part 931;
(e) For Coast Guard regulations on the oil spill liability of vessels and operators, see 33 CFR parts 132, 135, and 136.
(f) For Coast Guard regulations on port access routes, see 33 CFR part 164.
(g) For compliance with the National Environmental Policy Act, see 40 CFR parts 1500 through 1508.
(h) For Department of Transportation regulations on offshore pipeline facilities, see 49 CFR part 195.
(i) For Department of Defense regulations on military activities on offshore areas, see 32 CFR part 252.
(a) Any area of the OCS which has been appropriately platted as provided
(b) The MMS shall prepare leasing maps and official protraction diagrams of areas of the OCS. The areas included in each mineral lease shall be in accordance with the appropriate leasing map or official protraction diagram.
(a) The information covered in this section is prepared by or directly obtained by the Director. Such information is typically not considered to be proprietary or privileged, with the primary exception of specific indications of interest in an area by industry received in response to a Call for Information issued by the Secretary. This information and all other proprietary and privileged information obtained by or under the control of the Minerals Management Service may be released only in accordance with the regulations in 30 CFR parts 250, 251, and 252.
(b) The Director shall prepare an index to OCS information (see 30 CFR 252.5). The index shall list all relevant actual or proposed programs, plans, reports, environmental impact statements, nominations information, environmental study reports, lease sale information and any similar type of relevant information including, modifications, comments and revisions, prepared by or directly obtained by the Director under the act. The index shall be sent on a regular basis to affected States and, upon request, it shall be sent to any affected local government. The public shall be informed of the availability of the index.
(c) Upon request, the Director shall transmit to affected States, local governments or the public, a copy of any information listed in the index which is subject to the control of the MMS in accordance with the requirements and subject to the limitations of the Freedom of Information Act (5 U.S.C. 552) and regulations implementing said Act, and the regulations contained in 43 CFR part 2, except as provided in paragraph (d) of this section.
(d) Upon request, the Director shall provide relative indications of interest in areas as well as any comments filed in response to a Call for Information for a proposed sale. However, no information transmitted shall identify any particular area with the name of any particular party so as not to compromise the competitive position of any participants in the process of indicating interest.
(a) Each lease issued or continued under these regulations shall be subject to a reservation by the United States, under section 12(f) of the Act, of the ownership of and the right to extract helium from all gas produced from the leased area.
(b) In case the United States elects to take the helium, the lessee shall deliver all gas containing helium, or the portion of gas desired, to the United States at any point on the leased area or at an onshore processing facility. Delivery shall be made in the manner required by the United States to such plants or reduction works as the United States may provide.
(c) The extraction of helium shall not cause a reduction in the value of the lessee's gas or any other loss for which he is not reasonably compensated, except for the value of the helium extracted. The United States shall determine the amount of reasonable compensation. The United States shall have the right to erect, maintain and operate on the leased area any and all reduction works and other equipment necessary for the extraction of helium. The extraction of helium shall not cause substantial delays in the delivery of natural gas produced to the purchaser of that gas.
(a) The Secretary may conduct a supplemental sale in accordance with the provisions of this section.
(b) Supplemental sales shall be governed by the regulations in this part, except § 256.22.
(c) Supplemental sales shall be limited to blocks falling into one or more of the following categories:
(1) Blocks for which bids were rejected during the calendar year preceding the year of the supplemental sale in which they are reoffered or blocks for which bids were rejected in the same calendar year as the supplemental sale in which they are reoffered, except that for the initial supplemental sale only blocks for which bids were rejected after October 1, 1987, may be reoffered. If, after the initial supplemental sale, a supplemental sale is not held annually for any reason, the relevant period for determining blocks eligible for a subsequent supplemental sale may be extended to include rejected bid blocks which were eligible for the supplemental sale not held.
(2) Blocks for which the high bid was forfeited during the calendar year preceding the year of the supplemental sale in which they are reoffered or blocks for which high bids were forfeited in the same calendar year as the supplemental sale in which they are reoffered, except that for the initial supplemental sale only blocks for which high bids were forfeited after October 1, 1987, may be reoffered. If, after the initial supplemental sale, a supplemental sale is not held annually for any reason, the relevant period for determining blocks eligible for a subsequent sale may be extended to include forfeited bid blocks which were eligible for the supplemental sale not held.
(3) Development blocks. Development blocks (including blocks susceptible to drainage) are blocks which are located on the same general geologic structure as an existing lease having a well with indicated hydrocarbons; the reservoir may or may not be interpreted to extend on to the block.
(d) Supplemental sales shall not include blocks in the Central or Western Gulf of Mexico Planning Areas.
(e) The Director may disclose the classification of blocks in supplemental sales as development blocks.
As used in this subpart, the term—
(a) During preparation of a proposed 5-year leasing program, the Secretary shall invite and consider suggestions and relevant information for such program from Governors of affected States, local government, industry, other Federal agencies, including the Attorney General in consultation with the Federal Trade Commission, and all interested parties, including the general public. This request for information shall be issued as a notice in the
(b) The Secretary shall send letters to the Governors of the affected States requesting them to identify specific laws, goals, and policies which they believe should be considered by the Secretary in connection with the leasing program. The Secretary shall also request from the Secretary of Energy information on regional and national energy markets, on OCS production goals and on transportation networks.
(a)(1) The Secretary shall prepare a proposed leasing program. At least 60
(2) The Secretary shall reply in writing to any comment on the draft of the proposed program from the Governor of an affected State which is received at least 15 days prior to the submission of the proposed program to the Congress and publication in the
(b) The proposed leasing program shall be submitted to the Governors of the affected States for review and comment at the time it is submitted to the Congress and the Attorney General and published in the
(c) At least 60 days prior to approving the final leasing program and any later significant revision, the Secretary shall submit it to the President and the Congress, together with any comments. The Secretary shall indicate in such submission why any specific recommendation of the Attorney General or of a State or local government was not accepted.
The Secretary shall provide for periodic consultation with State and local governments, existing and potential oil and gas lessees and permittees, and representatives of other individuals or organizations engaged in any activity in or on the OCS, including those involved in fish and shellfish recovery, and recreational activities. This consultation shall take place primarily through appropriate public notice as described in §§ 256.16 and 256.17 and through the OCS Advisory Board and its committees, on a regional and national basis. Meetings of the OCS Advisory Board shall be held on specific issues as required by the Board's charter.
In the development of the leasing program, consideration shall be given to the coastal zone management program being developed or administered by an affected coastal State under section 305 or 306 of the Coastal Zone Management Act of 1972 as amended, (16 U.S.C. 1454, 1455). Information concerning the relationship between a State's coastal zone management program and OCS oil and gas activity shall be requested from the Governors of the affected coastal States and from the Secretary of Commerce prior to the development of the proposed leasing program at the time information is requested under § 256.16 of this part.
For oil and gas lease sales shown in an approved leasing schedule and as the need arises for other mineral leasing, the Director shall prepare a report describing the general geology and potential mineral resources of the area under consideration. The Director may
(a) The Director may receive and consider indications of interest in areas for mineral leasing.
(b) In accordance with an approved program and schedule for the leasing of OCS lands which may contain oil and gas, the Director shall issue Calls for Information and Nominations on areas for leasing of such minerals in specified areas. The Call for Information and Nominations shall be published in the
(a) At the time information is solicited for leasing of areas within 3 geographical miles seaward of the seaward boundary of any coastal State, the Secretary shall provide the Governor of that State information required under section 8(g)(1) of the Act. The Director shall furnish information identifying the areas for leasing as well as all relevant available environmental data for such areas (See 30 CFR 251.14).
(b) After receipt of information on areas within the area described in paragraph (a) of this section, the Secretary shall inform the Governor of those areas that are to be given further consideration for leasing. The Secretary shall enter into consultation with the Governor to determine whether the area may contain oil or gas pools or fields underlying both the OCS and lands subject to the jurisdiction of the State.
(c) After selection for leasing of those tracts which may have oil or gas pools or fields underlying both the OCS and lands under State jurisdiction, the Secretary shall offer the Governor an opportunity to enter into an agreement for the equitable disposition of revenues from such tracts under section 8(g)(2) of the Act.
(d) If no agreement can be reached within 90 days of the Secretary's offer, the tracts may be leased and all revenues deposited in a separate Treasury account pending equitable disposition of the revenues under sections 8(g) (3) and (4) of the Act.
(a) The Director, in consultation with appropriate Federal Agencies, shall recommend to the Secretary areas identified for environmental analysis and consideration for leasing. The Director, on his/her own motion, may include in the recommendation areas in which interest has not been indicated in response to a call. In making a recommendation, the Director shall consider all available environmental information, multiple-use conflicts, resource potential, industry interest and other relevant information. Comments received from States and local governments and interested parties in response to calls for information and nominations shall be considered in making recommendations. For supplemental sales provided for by § 256.12 of
(b) The Director shall evaluate fully the potential effect of leasing on the human, marine and coastal environments, and develop measures to mitigate adverse impacts, including lease stipulations. The views and recommendations of Federal agencies, State agencies, local governments, organizations, industries and the general public shall be used as appropriate. The Director may hold public hearings on the environmental analysis after appropriate notice.
(c) In general, the Director shall seek to inform the public as soon as possible of additions or deletions that occur after the identification of areas.
(a) A tract selected for oil and gas leasing shall consist of a compact area not exceeding 5,760 acres, unless the authorized officer finds that a larger area is necessary to comprise a reasonable economic production unit.
(b) The tract size for the leasing of other minerals shall be specified in the notice of sale.
(a) The Director shall in consultation with appropriate Federal agencies develop measures, including lease stipulations and conditions, to mitigate adverse impacts on the environments. For oil and gas lease sales, appropriate proposed stipulations and conditions shall be contained or referenced in the proposed notice of lease sale.
(b) A proposed notice of lease sale shall be submitted to the Secretary for approval. All comments and recommendations received and the Director's findings or actions thereon, shall also be forwarded to the Secretary.
(c) Upon approval by the Secretary, the proposed Notice of Sale shall be sent to the Governor of any affected State and a notice of its availability shall be published in the
(a) Within 60 days after notice of a proposed lease sale, a Governor of any affected State or any affected local government in such State may submit recommendations to the Secretary regarding the size, timing or location of the proposed lease sale. Prior to submitting recommendations to the Secretary, any affected local government shall forward such recommendation to the Governor.
(b) The Secretary shall accept such recommendations of the Governor and may accept recommendations of any affected local government if he determines, after having provided the opportunity for consultation, that they provide for a reasonable balance between the national interest and the well-being of the citizens of the affected State. A determination of the national interest shall be based on the findings, purposes and policies of the Act.
(c) The Secretary shall communicate to the Governor, in writing, the reasons for his determination to accept or reject such Governor's recommendations, or to implement any alternative means identified in consultation with the Governor to provide for a reasonable balance between the national interest and the well-being of the citizens of the affected State.
(a) Upon approval of the Secretary, the Director shall publish the notice of lease sale in the
(b) Tracts shall be offered for lease by competitive sealed bidding under conditions specified in the notice of lease sale and in accordance with all applicable laws and regulations. A suggested format for bidder submissions appears in appendix A of this part.
(c) The notice of lease sale shall contain a reference to the OCS lease form which shall be issued to successful bidders.
(d) With the approval of the Secretary, the Director may defer any part of the payment of the cash bonus according to a schedule announced at the time of the notice of lease sale. Payment shall be made no later than 5 years after the date of the lease sale. The schedule shall contain provisions for guaranteed payment of a deferred bonus.
(e) In order to obtain statistical information to determine which bidding alternatives best accomplish the purposes and policies of the Act, the Director may, until September 18, 1983, require each bidder to submit bids for any OCS area in accordance with more than one of the bidding systems described in section 8(a)(1) of the Act. No more than 10 percent of the tracts offered each year shall contain such a requirement. Leases may be awarded using a bidding alternative selected at random for statistical purposes, if it is otherwise consistent with the purposes and policies of the Act.
(a) In accordance with section 8 of the Act, leases shall be awarded only to the highest responsible qualified bidder.
(b) Mineral leases issued pursuant to section 8 of the Act may be held only by: (1) Citizens and nationals of the United States, (2) aliens lawfully admitted for permanent residence in the United States as defined in 8 U.S.C. 1101(a)(20); (3) private, public or municipal corporations organized under the laws of the United States or of any State or of the District of Columbia or territory thereof, or (4) associations of such citizens, nationals, resident aliens, or private, public, or municipal corporations, States, or political subdivisions of States.
(c) MMS may disqualify you from acquiring any new leaseholdings or lease assignments if your operating performance is unacceptable according to 30 CFR 250.135.
(a)(1) All oil and gas leases shall be issued for an initial period of 5 years, or not to exceed 10 years where the authorized officer finds that such longer period is necessary to encourage exploration and development in areas because of unusually deep water or other unusually adverse conditions.
(2) If your oil and gas lease is in water depths between 400 and 800 meters, it will have an initial lease term of 8 years unless MMS establishes a different lease term under paragraph (a)(1) of this section.
(3) For leases issued with an initial term of 8 years, you must begin an exploratory well within the first 5 years of the term to avoid lease cancellation.
(b) An oil and gas lease shall continue after such initial period for as long as oil or gas is produced from the lease in paying quantities, or drilling or well reworking operations as approved by the Secretary are conducted. The term of an oil and gas lease is subject to further extension as provided in § 256.73 of this part.
(c) Sulphur leases shall be issued for a term not to exceed 10 years and so long thereafter as sulphur is produced from the leasehold in paying quantities, or drilling, well reworking, plant construction, or other operations for the production of sulphur, as approved by the Secretary, are conducted thereon.
The following definitions shall be applicable to § 256.38 of this part:
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(1)
(2)
(3)
(k)
(l)
(i) Net differences between opening and closing inventories, and
(ii) Basic sediment and water;
(2)
(i) The volume of gas returned to natural reservoirs; and
(ii) The reduction of volume resulting from the removal of natural gas liquids and nonhydrocarbon gases.
(3)
(i)
(ii)
(A) Ethane—C
(B) Propane—C
(C) Butane—C
(
(
(
(D) Butane-Propane Mixtures—All products covered by NGPA specifications for butane-propane mixtures;
(E) Natural Gasoline—A mixture of hydrocarbons extracted from natural gas, which meet vapor pressure, end point, and other specifications for natural gasoline set by NGPA;
(F) Plant Condensate—A natural gas plant product recovered and separated as a liquid at gas inlet separators or scrubbers in processing plants or field facilities; and
(G) Other Natural Gas Plant Products meeting refined product standards (i.e., gasoline, kerosene, distillate, etc.).
(m)
(1) From May 1 through October 31; or
(2) From November 1 through April 30, respectively.
(a) Any person who submits a joint bid for any oil and gas lease during a 6-month bidding period, and who was chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products, shall have filed under oath with the Director, a Statement of Production of crude oil, natural gas and liquified petroleum products, hereinafter referred to as a Statement of Production, no later than 45 days prior to the commencement of the applicable 6-month bidding period of May 1 through October 31, and November 1 through April 30. Statements of Production shall be submitted to the Director, MMS (Attention: Offshore Leasing Management Division), Washington, DC 20240. The Statement of Production shall indicate that the person was chargeable, in accordance with § 256.43 of this part, with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products for the prior production period. The Director shall publish semi-annually in the
(b) When a person is placed on the List of Restricted Joint Bidders the Director shall serve that person either personally or by certified mail, return receipt requested, with a copy of the Director's Order placing that person on the List of Restricted Joint Bidders. Any appeal from that Order or from an adverse effect of that Order shall be made in accordance with the provisions of 43 CFR part 4.
(c) The submission of a Statement of Production or of a detailed Report of Production under § 256.46(g) of this part which misrepresents the chargeable production of the reporting person shall constitute failure to comply with these regulations and any lease awarded in reliance on that Statement or Report of Production may be canceled, pursuant to section 8(o) of the Act and regulations issued thereunder as having been obtained by fraud or misrepresention.
(d) The Secretary may exempt a person from the provisions of §§ 256.41(a), 256.44, 256.46(g) and 256.62(b) of this part if it is found, on the record, after an opportunity for an agency hearing,
(a) As used in this section the following definitions shall control:
(1)
(2)
(3)
(4)
(b) A person filing a Statement of Production under § 256.41 of this part shall be charged with the following production during the applicable prior production period:
(1) The average daily production in barrels of crude oil, natural gas, and liquefied petroleum products which it owned worldwide;
(2) The average daily production in barrels of crude oil, natural gas, and liquefied petroleum products owned worldwide by every subsidiary of the reporting person;
(3) The average daily production in barrels of crude oil, natural gas, and liquefied petroleum products owned worldwide by any person or persons of which the reporting person is a subsidiary; and
(4) The average daily production in barrels of crude oil, natural gas, and liquefied petroleum products owned worldwide by any subsidiary, other than the reporting person, of any person or persons of which the reporting person is a subsidiary.
(c) A person filing a Statement of Production shall be charged with, in addition to the production chargeable under paragraph (b) of this section, but not in duplication thereof, its proportionate share of the average daily production in barrels of crude oil, natural gas, and liquefied petroleum products owned worldwide by every person:
(1) Which has an interest in the reporting person, and
(2) In which the reporting person has an interest, whether the interest referred to in paragraphs (c) (1) and (2) of this section is by virtue of ownership of securities or other evidence of ownership, or by participation in any contract, agreement, or understanding respecting the control of any person or of any person's production of crude oil, natural gas, or liquefied petroleum products, equal to said interest. As used in paragraph (c) of this section “interest” means an interest of at least 5 percent of the ownership or control of a person.
(d) All measurements of crude oil and liquefied petroleum products under this section shall be at 60 °F.
(e)(1) For purposes of computing production of natural gas under § 256.41 of this part, chargeability under this section, and reporting under § 256.46(g) of this part, 5,626 cubic feet of natural gas at 14.73 pounds per square inch (msl) shall equal one barrel.
(2) For purposes of computing production of liquefied petroleum products under § 256.41 of this part, chargeability under § 256.46(g) of this part, 1.454 barrels of natural gas liquids at 60 °F shall equal one barrel of crude oil.
The following bids for any oil and gas lease shall be disqualified and rejected in their entirety:
(a) A joint bid submitted by 2 or more persons who are on the effective List of Restricted Joint Bidders; or
(b)(1) A joint bid submitted by two or more persons when 1 or more of those persons is chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products and has not filed a Statement of Production as required by § 256.41 of this part for the applicable 6-month bidding period, or
(2) Any of those persons have failed or refused to file a detailed report of production when required to do so under § 256.46(g) of this part, or
(c) A single or joint bid submitted pursuant to an agreement (whether written or oral, formal or informal, entered into or arranged prior to or simultaneously with the submission of such single or joint bid, or prior to or simultaneously with the award of the bid upon the tract) which provides:
(1) For the assignment, transfer, sale, or other conveyance of less than a 100 percent interest in the entire tract on which the bid is submitted, by a person or persons on the List of Restricted Joint Bidders, effective on the date of submission of the bid, to another person or persons on the same List of Restricted Joint Bidders; or
(2) For the assignment, sale, transfer or other conveyance of less than a 100 percent interest in any fractional interest in the entire tract (which fractional interest was originally acquired by the person making the assignment, sale, transfer or other conveyance, under the provisions of the act) by a person or persons on the List of Restricted Joint Bidders, effective on the date of submission of the bid, to another person or persons on the same List of Restricted Joint Bidders; or
(3) For the assignment, sale, transfer, or other conveyance of any interest in a tract by a person or persons not on the List of Restricted Joint Bidders, effective on the date of submission of the bid, to 2 or more persons on the same List of Restricted Joint Bidders; or
(4) For any of the types of conveyances described in paragraphs (c) (1), (2) or (3) of this section where any party to the conveyance is chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas and liquified petroleum products and has not filed a Statement of Production pursuant to § 256.41 of this part for the applicable 6-month bidding period. Assignments expressly required by law, regulation, lease or stipulation to lease shall not disqualify an otherwise qualified bid; or
(d) A bid submitted by or in conjunction with a person who has filed a false, fraudulent or otherwise intentionally false or misleading detailed Report of Production.
(a) A separate sealed bid shall be submitted for each tract unit bid upon as described in the notice of lease sale. A bid may not be submitted for less than an entire tract.
(b) MMS requires a deposit for each bid. The notice of sale will specify the bid deposit amount and method of payment.
(c) If the bidder is an individual a statement of citizenship shall accompany the bid.
(d) If the bidder is an association (including a partnership), the bid shall be accompanied by a certified statement indicating the State in which it is registered and that it is authorized to hold mineral leases on the OCS, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations).
(e) If the bidder is a corporation, the following information shall be submitted with the bid:
(1) A statement certified by the corporate Secretary or Assistant Secretary over the corporate seal showing the State in which it was incorporated and that it is authorized to hold mineral leases on the OCS, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations).
(2) Evidence of authority of persons signing to bind the corporation. Such evidence may be in the form of either a certified copy of the minutes of the board of directors or of the bylaws indicating that the person signing has authority to do so; or a certificate to that effect signed by the Secretary or Assistant Secretary of the corporation over the corporate seal, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations). Bidders are advised to keep their filings current.
(3) The bid shall be executed in conformance with corporate requirements.
(f) Bidders should be aware of the provisions of 18 U.S.C. 1860, prohibiting unlawful combination or intimidation of bidders.
(g) To verify the accuracy of any statement submitted pursuant to § 256.41 of this part, the Director may require the person submitting such information to:
(1) Submit no later than 30 days after receipt of the request by the Director, a detailed Report of Production which shall list, in barrels, the average daily production of crude oil, natural gas and liquefied petroleum products chargeable to the reporting person in accordance with § 256.43 of this part for the prior production period, and
(2) Permit the inspection and copying by an official of the Department of the Interior of such documents, records of production of crude oil, natural gas and liquified petroleum products, analyses and other material as are necessary to demonstrate the accuracy of any statement or information contained in any Report of Production.
(h) No bid for a lease may be submitted if the Secretary finds, after notice and hearing, that the bidder is not meeting due diligence requirements on other OCS leases.
(a) Sealed bids received in response to the notice of lease sale shall be opened at the place, date and hour specified in the notice. The opening of bids is for the sole purpose of publicly announcing and recording the bids received and no bids shall be accepted or rejected at that time.
(b) The United States reserves the right to reject any and all bids received for any tract, regardless of the amount offered.
(c) In the event the highest bids are tie bids, the tie bidders (unless they would be disqualified under § 256.35(b) of this part, or disqualified under § 256.44 of this part if their bids had been joint bids) may file with the Director, within 15 days after notification, an agreement to accept the lease jointly; otherwise all bids shall be rejected.
(d) Pursuant to section 8(c) of the Act, the Attorney General may review the results of the lease sale prior to the acceptance of bids and issuance of leases.
(e)(1) The decision of the authorized officer on bids shall be the final action of the Department, subject only to reconsideration by the Secretary, pursuant to written request, of the rejection of the high bid. The delegation of review authority to the Office of Hearings and Appeals shall not be applicable to decisions on high bids for leases on the Outer Continental Shelf.
(2) The authorized officer must accept or reject the bid within 90 days. The authorized officer may extend the time period for acceptance or rejection of a bid for 15 working days or longer, if circumstances warrant. Any bid not accepted within the prescribed time period, including any extension thereof, is deemed rejected.
(3) Any high bidder whose bid is rejected by the authorized officer may, within 15 days of such rejection, file
(f) Written notice of the authorized officer's action shall be transmitted promptly to those bidders whose deposits have been held. If a bid is accepted, such notice shall transmit three copies of the lease to the successful bidder. As provided in § 218.155, the bidder shall, not later than the 11th business day after receipt of the lease, execute the lease, pay the first-year's rental, and unless deferred, pay the balance of the bonus bid. The bidder must also file a bond as required in § 256.52 of this title. Deposits and any interest accrued shall be refunded on high bids subsequently rejected.
(g) If the successful bidder fails to execute the lease within the prescribed time or otherwise comply with the applicable regulations the deposit shall be forfeited and disposed of as other receipts under the act.
(h) If, before the lease is executed on behalf of the United States, the land which would be subject to the lease is withdrawn or restricted from leasing, all deposits and any interest due shall be refunded.
(i) If the awarded lease is executed by an agent acting on behalf of the bidder, the lease shall be accompanied by evidence that the bidder authorized the agent to execute the lease. When three copies of the lease are executed and returned to the authorized officer, the lease shall be executed on behalf of the United States, and one fully executed copy shall be transmitted to the successful bidder.
(j) No lease or permit shall be issued for any area within 15 statute miles of the boundaries of the Point Reyes Wilderness in California unless the State of California allows exploration, development or production activities in the adjacent navigable waters of the State under section 11(h) of the Act.
Oil and gas leases and leases for sulphur shall be issued on forms approved by the Director. Other mineral leases shall be issued on such forms as may be prescribed by the Secretary.
All leases issued under the regulations in this part shall be dated and become effective as of the first day of the month following the date leases are signed on behalf of the lessor. When prior written request is made, a lease may be dated and become effective as of the first day of the month within which it is so signed.
This section establishes bond requirements for the lessee of an OCS oil and gas or sulphur lease.
(a) Before MMS will issue a new lease or approve the assignment of an existing lease to you as lessee, you or another record title owner for the lease must:
(1) Maintain with the Regional Director a $50,000 lease bond that guarantees compliance with all the terms and conditions of the lease; or
(2) Maintain a $300,000 areawide bond that guarantees compliance with all the terms and conditions of all your oil and gas and sulphur leases in the area where the lease is located; or
(3) Maintain a lease or areawide bond in the amount required in § 256.53(a) or (b) of this part.
(b) For the purpose of this section, there are three areas. The area offshore the Atlantic Coast is included in the Gulf of Mexico. Areawide bonds issued in the Gulf of Mexico will cover oil and gas or sulphur operations offshore the Atlantic Coast. The three areas are:
(1) The areas offshore the Gulf of Mexico and Atlantic Coast;
(2) The area offshore the Pacific Coast States of California, Oregon, Washington, and Hawaii; and
(3) The area offshore the Coast of Alaska.
(c) The requirement to maintain a lease bond (or substitute security instruments) under paragraph (a)(1) of this section and § 256.53 (a) and (b) is satisfied if your operator provides a lease bond in the required amount that guarantees compliance with all the terms and conditions of the lease. Your operator may use an areawide bond under this paragraph to satisfy your bond obligation.
(d) If a surety makes payment to the United States under a bond or alternate form of security maintained under this section, the surety's remaining liability under the bond or alternate form of security is reduced by the amount of that payment. See paragraph (e) of this section for the requirement to replace the reduced bond coverage.
(e) If the value of your surety bond or alternate security is reduced because of a default, or for any other reason, you must provide additional bond coverage sufficient to meet the security required under this subpart within 6 months, or such shorter period of time as the Regional Director may direct.
(f) You may pledge U.S. Department of the Treasury (Treasury) securities instead of a bond. The Treasury securities you pledge must be negotiable for an amount of cash equal to the value of the bond they replace.
(1) If you pledge Treasury securities under this paragraph (f), you must monitor their value. If their market value falls below the level of bond coverage required under this subpart, you must pledge additional Treasury securities to raise the value of the securities pledged to the required amount.
(2) If you pledge Treasury securities, you must include authority for the Regional Director to sell them and use the proceeds when the Regional Director determines that you fail to satisfy any lease obligation.
(g) You may pledge alternate types of security instruments instead of providing a bond if the Regional Director determines that the alternate security protects the interests of the United States to the same extent as the required bond.
(1) If you pledge an alternate type of security under this paragraph, you must monitor the security's value. If its market value falls below the level of bond coverage required under this subpart, you must pledge additional securities to raise the value of the securities pledged to the required amount.
(2) If you pledge an alternate type of security, you must include authority for the Regional Director to sell the security and use the proceeds when the Regional Director determines that you failed to satisfy any lease obligation.
(h) If you fail to replace a deficient bond or to provide additional bond coverage upon demand, the Regional Director may:
(1) Assess penalties under part 250, subpart N of this chapter;
(2) Suspend production and other operations on your leases in accordance with § 250.110 of this chapter; and
(3) Initiate action to cancel your lease.
(a) This paragraph explains what bonds the lessee must provide before lease exploration activities commence.
(1)(i) You must furnish the Regional Director a $200,000 bond that guarantees compliance with all the terms and conditions of the lease by the earliest of:
(A) The date you submit a proposed Exploration Plan (EP) for approval;
(B) The date you submit a request for approval of the assignment of a lease on which an EP has been approved; or
(C) December 8, 1997, for any lease for which an EP has been approved.
(ii) The Regional Director may authorize you to submit the $200,000 lease exploration bond after you submit an EP but before he/she approves drilling activities under the EP.
(iii) You may satisfy the bond requirement of this paragraph (a) by providing a new bond or by increasing the amount of your existing bond.
(2) A $200,000 lease exploration bond pursuant to paragraph (a)(1) of this section need not be submitted and maintained if the lessee either:
(i) Furnishes and maintains an areawide bond in the sum of $1 million issued by a qualified surety and conditioned on compliance with all the terms and conditions of oil and gas and sulphur leases held by the lease on the OCS for the area in which the lessee is situated; or
(ii) Furnishes and maintains a bond pursuant to paragraph (b)(2) of this section.
(b) This paragraph explains what bonds you (the lessee) must provide before lease development and production activities commence.
(1)(i) You must furnish the Regional Director a $500,000 bond that guarantees compliance with all the terms and conditions of the lease by the earliest of:
(A) The date you submit a proposed Development and Production Plan (DPP) or Development Operations Coordination Document (DOCD) for approval;
(B) The date you submit a request for approval of the assignment of a lease on which a DPP or DOCD has been approved; or
(C) December 8, 1997, for any lease for which a DPP or DOCD has been approved.
(ii) The Regional Director may authorize you to submit the $500,000 lease development bond after you submit a DPP or DOCD, but before he/she approves the installation of a platform or the commencement of drilling activities under the DPP or DOCD.
(iii) You may satisfy the bond requirement of this paragraph by providing a new bond or by increasing the amount of your existing bond.
(2) The lessee need not submit and maintain a $500,000 lease development bond pursuant to paragraph (b)(1) of this section if the lessee furnishes and maintains an areawide bond in the sum of $3 million issued by a qualified surety and conditioned on compliance with all the terms and conditions of oil and gas and sulphur leases held by the lessee on the OCS for the area in which the lease is situated.
(c) When a lessee can demonstrate to the satisfaction of the authorized officer that wells and platforms can be abandoned and removed and the drilling and platform sites cleared of obstructions for less than the amount of lease bond coverage required under paragraph (b)(1) of this section, the authorized officer may accept a lease surety bond in an amount less than the prescribed amount but not less than the amount of the cost for well abandonment, platform removal, and site clearance.
(d) The Regional Director may determine that additional security (i.e., security above the amounts prescribed in §§ 256.52(a) and 256.53 (a) and (b) of this part) is necessary to ensure compliance with the obligations under your lease and the regulations in this chapter.
(1) The Regional Director's determination will be based on his/her evaluation of your ability to carry out present and future financial obligations demonstrated by:
(i) Financial capacity substantially in excess of existing and anticipated lease and other obligations, as evidenced by audited financial statements (including auditor's certificate, balance sheet, and profit and loss sheet);
(ii) Projected financial strength significantly in excess of existing and future lease obligations based on the estimated value of your existing OCS lease production and proven reserves of future production;
(iii) Business stability based on 5 years of continuous operation and production of oil and gas or sulphur in the OCS or in the onshore oil and gas industry;
(iv) Reliability in meeting obligations based on:
(A) Credit rating(s); or
(B) Trade references, including names and addresses of other lessees, drilling contractors, and suppliers with whom you have dealt; and
(v) Record of compliance with laws, regulations, and lease terms.
(2) You may satisfy the Regional Director's demand for additional security by increasing the amount of your existing bond or by providing a supplemental bond or bonds.
(e) The Regional Director will determine the amount of supplemental bond required to guarantee compliance. The Regional Director will consider potential underpayment of royalty and cumulative obligations to abandon wells, remove platforms and facilities, and clear the seafloor of obstructions in the Regional Director's case-specific analysis.
(f) If your cumulative potential obligations and liabilities either increase or decrease, the Regional Director may adjust the amount of supplemental bond required.
(1) If the Regional Director proposes an adjustment, the Regional Director will:
(i) Notify you and the surety of any proposed adjustment to the amount of bond required; and
(ii) Give you an opportunity to submit written or oral comment on the adjustment.
(2) If you request a reduction of the amount of supplemental bond required, you must submit evidence to the Regional Director demonstrating that the projected amount of royalties due the Government and the estimated costs of lease abandonment and cleanup are less than the required bond amount. If the Regional Director finds that the evidence you submit is convincing, he/she may reduce the amount of supplemental bond required.
(a) Any bond or other security that you, as lessee or operator, provide under this part must:
(1) Be payable upon demand to the Regional Director;
(2) Guarantee compliance with all of your obligations under the lease and regulations in this chapter; and
(3) Guarantee compliance with the obligations of all lessees, operating rights owners and operators on the lease.
(b) All bonds and pledges you furnish under this part must be on a form or in a form approved by the Associate Director for Offshore Minerals Management. Surety bonds must be issued by a surety that the Treasury certifies as an acceptable surety on Federal bonds and that is listed in the current Treasury Circular No. 570. You may obtain a copy of the current Treasury Circular No. 570 from the Surety Bond Branch, Financial Management Service, Department of the Treasury, East-West Highway, Hyattsville, MD 20782.
(c) You and a qualified surety must execute your bond. When either party is a corporation, an authorized official for the party must sign the bond and attest to it by an imprint of the corporate seal.
(d) Bonds must be noncancellable, except as provided in § 256.58 of this part. Bonds must continue in full force and effect even though an event occurs that could diminish, terminate, or cancel a surety obligation under State surety law.
(e) Lease bonds must be:
(1) A surety bond;
(2) Treasury securities as provided in § 256.52(f);
(3) Another form of security approved by the Regional Director; or
(4) A combination of these security methods.
(f) You may submit a bond to the Regional Director executed on a form approved under paragraph (b) of this section that you have reproduced or generated by use of a computer. If you do this, and if the document omits terms or conditions contained on the form approved by the Associate Director for Offshore Minerals Management the bond you submit will be deemed to contain the omitted terms and conditions.
(a) If your surety becomes bankrupt, insolvent, or has its charter or license suspended or revoked, any bond coverage from that surety terminates immediately. In that event, you must promptly provide a new bond in the amount required under §§ 256.52 and
(b) You must notify the Regional Director of any action filed alleging that you, your surety, or guarantor are insolvent or bankrupt. You must notify the Regional Director within 72 hours of learning of such an action. All bonds must require the surety to provide this information to you and directly to MMS.
(a) The Regional Director may authorize you to establish a lease-specific abandonment account in a federally insured institution in lieu of the bond required under § 256.53(d). The account must provide that, except as provided in paragraph (a)(3) of this section, funds may not be withdrawn without the written approval of the Regional Director.
(1) Funds in a lease-specific abandonment account must be payable upon demand to MMS and pledged to meet the lessee's obligations under § 250.700 of this chapter.
(2) You must fully fund the lease-specific abandonment account to cover all the costs of lease abandonment and site clearance as estimated by MMS within the timeframe the Regional Director prescribes.
(3) You must provide binding instructions under which the institution managing the account is to purchase Treasury securities pledged to MMS under paragraph (d) of this section.
(b) Any interest paid on funds in a lease-specific abandonment account will be treated as other funds in the account unless the Regional Director authorizes in writing the payment of interest to the party who deposits the funds.
(c) The Regional Director may allow you to pledge Treasury securities that are made payable upon demand to the Regional Director to satisfy your obligation to make payments into a lease-specific abandonment account.
(d) Before the amount of funds in a lease-specific abandonment account equals the maximum insurable amount as determined by the Federal Deposit Insurance Corporation or the Federal Savings and Loan Insurance Corporation, the institution managing the account must use the funds in the account to purchase Treasury securities pledged to MMS under paragraph (c) of this section. The institution managing the lease specific-abandonment account will join with the Regional Director to establish a Federal Reserve Circular 154 account to hold these Treasury securities, unless the Regional Director authorizes the managing institution to retain the pledged Treasury securities in a separate trust account. You may obtain a copy of the current Treasury Circular No. 154 from the Surety Bond Branch, Financial Management Service, Department of the Treasury, East-West Highway, Hyattsville, MD 20782.
(e) The Regional Director may require you to create an overriding royalty or production payment obligation for the benefit of a lease-specific account pledged for the abandonment and clearance of a lease. The required obligation may be associated with oil and gas or sulphur production from a lease other than the lease bonded through the lease-specific abandonment account.
(a)
(1) The guarantee meets the criteria in paragraph (c) of this section;
(2) The guarantee includes the terms specified in paragraph (d) of this section;
(3) The guarantor's total outstanding and proposed guarantees do not exceed 25 percent of its unencumbered net worth in the United States; and
(4) The guarantor submits an indemnity agreement meeting the criteria in paragraph (e) of this section.
(b)
(1) Notify the Regional Director immediately; and
(2) Cease production until you comply with the bond coverage requirements of this subpart.
(c)
(1) The period of time that your third-party guarantor (guarantor) has been in continuous operation as a business entity where:
(i) Continuous operation is the time that your guarantor conducts business immediately before you post the guarantee; and
(ii) Continuous operation excludes periods of interruption in operations that are beyond your guarantor's control and that do not affect your guarantor's likelihood of remaining in business during exploration, development, production, abandonment, and clearance operations on your lease.
(2) Financial information available in the public record or submitted by your guarantor, on your guarantor's own initiative, in sufficient detail to show to the Regional Director's satisfaction that your guarantor is qualified based on:
(i) Your guarantor's current rating for its most recent bond issuance by either Moody's Investor Service or Standard and Poor's Corporation;
(ii) Your guarantor's net worth, taking into account liabilities under its guarantee of compliance with all the terms and conditions of your lease, the regulations in this chapter, and your guarantor's other guarantees;
(iii) Your guarantor's ratio of current assets to current liabilities, taking into account liabilities under its guarantee of compliance with all the terms and conditions of your lease and the regulations in this chapter and your guarantor's other guarantees; and
(iv) Your guarantor's unencumbered fixed assets in the United States.
(3) When the information required by paragraph (c) of this section is not publicly available, your guarantor may submit the information in the following table. Your guarantor must update the information annually within 90 days of the end of the fiscal year or by the date prescribed by the Regional Director.
(d)
(1) If you, your operator, or an operating rights owner fails to comply with any lease term or regulation, your guarantor must either:
(i) Take corrective action; or
(ii) Be liable under the indemnity agreement to provide, within 7 calendar days, sufficient funds for the Regional Director to complete corrective action.
(2) If your guarantor complies with paragraph (d)(1) of this section, this compliance will not reduce its liability.
(3) If your guarantor wishes to terminate the period of liability under its guarantee, it must:
(i) Notify you and the Regional Director at least 90 days before the proposed termination date;
(ii) Obtain the Regional Director's approval for the termination of the period of liability for all or a specified portion of your guarantor's guarantee; and
(iii) Remain liable for all work and workmanship performed during the period that your guarantor's guarantee is in effect.
(4) You must provide a suitable replacement security instrument before the termination of the period of liability under your third-party guarantee.
(e)
(1) The indemnity agreement must be executed by your guarantor and all persons and parties bound by the agreement.
(2) The indemnity agreement must bind each person and party executing the agreement jointly and severally.
(3) When a person or party bound by the indemnity agreement is a corporate entity, two corporate officers who are authorized to bind the corporation must sign the indemnity agreement.
(4) Your guarantor and the other corporate entities bound by the indemnity agreement must provide the Regional Director copies of:
(i) The authorization of the signatory corporate officials to bind their respective corporations;
(ii) An affidavit certifying that the agreement is valid under all applicable laws; and
(iii) Each corporation's corporate authorization to execute the indemnity agreement.
(5) If your third-party guarantor or another party bound by the indemnity agreement is a partnership, joint venture, or syndicate, the indemnity agreement must:
(i) Bind each partner or party who has a beneficial interest in your guarantor; and
(ii) Provide that, upon demand by the Regional Director under your third-party guarantee, each partner is jointly and severally liable for compliance with all terms and conditions of your lease.
(6) When forfeiture is called for under § 256.59 of this part, the indemnity agreement must provide that your guarantor will either:
(i) Bring your lease into compliance; or
(ii) Provide, within 7 calendar days, sufficient funds to permit the Regional Director to complete corrective action.
(7) The indemnity agreement must contain a confession of judgment. It must provide that, if the Regional Director determines that you, your operator, or an operating rights owner is in default of the lease, the guarantor:
(i) Will not challenge the determination; and
(ii) Will remedy the default.
(8) Each indemnity agreement is deemed to contain all terms and conditions contained in this paragraph (e), even if the guarantor has omitted them.
This section defines the terms and conditions under which the Regional Director may terminate the period of liability of a bond or cancel a bond.
(a) When the surety under your bond requests termination of the period of liability under its bond, the Regional Director will terminate the period of liability under your bond and demand that you provide a replacement bond of equivalent amount.
(1) Termination of the period of liability under a bond does not release the surety of that bond.
(2) Your surety is responsible for all obligations and liabilities that accrue before the effective date of the Regional Director's termination of the period of liability under its bond.
(b) The Regional Director's cancellation or release of a bond may include lease obligations that accrue before the effective date of the cancellation only when:
(1) The Regional Director determines that there are no outstanding obligations; or
(2) You furnish a replacement bond:
(i) In which your new surety agrees to assume all outstanding liabilities under the bond that is to be canceled; and
(ii) That is in an amount equal to or greater than the amount of the bond that is to be canceled.
(c) The Regional Director will issue a written instrument to cancel or release your bond. This instrument will subject the bond to automatic reinstatement, as if no cancellation or release had occurred, if:
(1) A person makes a payment under the lease and the payment is rescinded or must be repaid by the recipient because the person making the payment is insolvent, bankrupt, subject to reorganization, or placed in receivership; or
(2) The responsible party represents to MMS that it has discharged its obligations under the lease and the representation is materially false when the bond is canceled, or released.
This section explains how a bond or other security may be forfeited.
(a) The Regional Director will call for forfeiture of all or part of the bond, other form of security, or guarantee you provide under this part if:
(1) You (the party who provided the bond) refuse, or the Regional Director determines that you are unable, to comply with any term or condition of your lease; or
(2) You default under one of the conditions under which the Regional Director accepts your bond, third-party guarantee, and/or other form of security.
(b) The Regional Director may pursue forfeiture of your bond without first making demands for performance against any lessee, operating rights owner, or other person authorized to perform lease obligations.
(c) The Regional Director will:
(1) Notify you, the surety on your bond or other form of security, and any third-party guarantor, of his/her determination to call for forfeiture of the bond, security, or guarantee under this section.
(i) This notice will be in writing and will provide the reasons for the forfeiture and the amount to be forfeited.
(ii) The Regional Director must base the amount he/she determines is forfeited upon his/her estimate of the total cost of corrective action to bring your lease into compliance.
(2) Advise you, your third-party guarantor, and any surety, that you, your guarantor, and any surety may avoid forfeiture if, within 5 working days:
(i) You agree to, and demonstrate that you will, bring your lease into compliance within the timeframe that the Regional Director prescribes;
(ii) Your third-party guarantor agrees to, and demonstrates that it will, complete the corrective action to bring your lease into compliance within the timeframe that the Regional Director prescribes; or
(iii) Your surety agrees to, and demonstrates that it will, bring your lease into compliance within the timeframe that the Regional Director prescribes, even if the cost of compliance exceeds the face amount of the bond or other surety instrument.
(d) If the Regional Director finds you are in default, he/she may cause the forfeiture of any bonds and other security deposited as your guarantee of compliance with the terms and conditions of your lease and the regulations in this chapter.
(e) If the Regional Director determines that your bond and/or other security is forfeited, the Regional Director will:
(1) Collect the forfeited amount; and
(2) Use the funds collected to bring your leases into compliance and to correct any default.
(f) If the amount the Regional Director collects under your bond and other security is insufficient to pay the full cost of corrective actions he/she may:
(1) Take or direct action to obtain full compliance with your lease and the regulations in this chapter; and
(2) Recover from you, any co-lessee, operating rights owner, and/or any third-party guarantor responsible under this subpart all costs in excess of the amount he/she collects under your forfeited bond and other security.
(g) The amount that the Regional Director collects under your forfeited bond and other security may exceed the costs of taking the corrective actions required to obtain full compliance with the terms and conditions of your lease and the regulations in this chapter. In this case, the Regional Director will return the excess funds to the party from whom they were collected.
This section explains how to assign record title and other interests in OCS oil and gas or sulphur leases.
(a) MMS may approve the assignment to you of the ownership of the record title to a lease or any undivided interest in a lease, or an officially designated subdivision of a lease, only if:
(1) You qualify to hold a lease under § 256.35(b);
(2) You provide the bond coverage required under subpart I of this part; and
(3) The Regional Director approves the assignment.
(b) An assignment shall be void if it is made pursuant to any prelease agreement described in § 256.44(c) of this part that would cause a bid to be disqualified.
(c) Any approved assignment shall be deemed to be effective on the first day of the lease month following its filing in the appropriate office of the MMS, unless at the request of the parties, an earlier date is specified in the approval.
(d) You, as assignor, are liable for all obligations that accrue under your lease before the date that the Regional Director approves your request for assignment of the record title in the lease. The Regional Director's approval of the assignment does not relieve you of accrued lease obligations that your assignee, or a subsequent assignee, fails to perform.
(e) Your assignee and each subsequent assignee are liable for all obligations that accrue under the lease after the date that the Regional Director approves the governing assignment. They must:
(1) Comply with all the terms and conditions of the lease and all regulations issued under the Act; and
(2) Remedy all existing environmental problems on the tract, properly abandon all wells, and reclaim the lease site in accordance with part 250, subpart G.
(f) If your assignee, or a subsequent assignee, fails to perform any obligation under the lease or the regulations in this chapter, the Regional Director may require you to bring the lease into compliance to the extent that the obligation accrued before the Regional Director approved the assignment of your interest in the lease.
This section explains how to file instruments with MMS that create and/or transfer interests in OCS oil and gas or sulphur leases.
(a) You must submit to the Regional Director for approval all instruments that create or transfer ownership of a lease interest.
(1) You must submit two copies of the instruments that create or transfer an interest. Each instrument that creates or transfers an interest must describe by officially designated subdivision the interest you propose to create or transfer.
(2) You must submit your proposal to create or transfer an interest, or create or transfer separate operating rights, subleases, and record title interests within 90 days of the last date that a party executes the transfer agreement.
(3) The transferee must meet the citizenship and other qualification criteria specified in § 256.35 of this part. When you submit an instrument to create or transfer an interest as an association, you must include a statement signed by the transferee about the transferee's citizenship and qualifications to own a lease.
(4) Your instrument to create or transfer an interest must contain all of the terms and conditions to which you and the other parties agree.
(5) You do not gain a release of any nonmonetary obligation under your lease or the regulations in this chapter by creating a sublease or transferring operating rights.
(6) You do not gain a release from any accrued obligation under your lease or the regulations in this chapter by assigning your record title interest in the lease.
(7) You may create or transfer carried working interests, overriding royalty interests, or payments out of production without obtaining the Regional Director's approval. However,
(8) A nonrefundable filing fee of $185 must accompany an application for approval of any instrument of transfer required to be filed. MMS periodically will amend the filing fee based on its experience with the costs for administering lease transfer applications. If the costs increase by more than the CPI “U,” MMS will provide notice and opportunity for comment before changing the filing fee. For lesser cost increases or cost reductions MMS will change the fee without such procedures. Any document not required to be filed by these regulations but submitted for record purposes shall be accompanied by a nonrefundable fee of $25 per lease affected. Such documents may be rejected at the discretion of the authorized officer.
(b) An attorney in fact, in behalf of the holder of a lease, operating rights or sublease, shall furnish evidence of authority to execute the assignment or application for approval and the statement required by § 256.46 of this part.
(c) When you request approval for an assignment that assigns all your record title interest in a lease or that creates a segregated lease, your assignee must furnish a bond in the amount prescribed in §§ 256.52 and 256.53 of this part.
(d) When you request approval for an assignment that assigns less than all the record title of a lease and that does not create a separate lease, the assignee may, with the surety's consent, become a joint principal on the surety instrument that guarantees compliance with all the terms and conditions of the lease.
(e) An heir or devisee of a deceased holder of a lease, or any interest therein, shall be recognized as the lawful successor to such lease or interest, if evidence of status as an heir or devisee is furnished in the form of:
(1) A certified copy of an appropriate order or decree of the court having jurisdiction of the distribution of the estate or,
(2) If no court action is necessary, the statements of two disinterested parties having knowledge of the facts or a certified copy of the will.
(f) In addition to the requirements of paragraph (d) of this section, the heirs or devisees shall file statements that they are the persons named as successors to the estate with evidence of their qualifications as provided in § 256.46 of this part.
(g) In the event an heir or devisee is unable to qualify to hold the lease or interest, the heir or devisee shall be recognized as the lawful successor of the deceased and be entitled to hold the lease for a period of not to exceed 2 years from the date of death of the predecessor in interest.
(h) Your heirs, executors, administrators, successors, and assigns are bound to comply with each obligation under any lease and under the regulations in this chapter.
(1) You are jointly and severally liable for the performance of each nonmonetary obligation under the lease and under the regulations in this chapter with each prior lessee and with each operating rights owner holding an interest at the time the obligation accrued, unless this chapter provides otherwise.
(2) Sublessees and operating rights owners are jointly and severally liable for the performance of each nonmonetary obligation under the lease and under the regulations in this chapter to the extent that:
(i) The obligation relates to the area embraced by the sublease;
(ii) Those owners held their respective interest at the time the obligation accrued; and
(iii) This chapter does not provide otherwise.
(i) Where the proposed assignment or transfer is by a person who, at the time of acquisition of an interest in the lease, was on the List of Restricted Joint Bidders, and that assignment or transfer is of less than the entire interest of the assignor or transferor, to a person or persons on the same List of Restricted Joint Bidders, the assignor or transferor shall file a copy, prior to approval of the assignment, of all
Prior to the approval of an assignment or transfer, the Secretary shall consult with and give due consideration to the views of the Attorney General. The Secretary may act on an assignment or transfer if the Attorney General has not responded to the request for consultation within 30 days of said request.
A separate instrument of assignment shall be filed for each lease. When transfers to the same person, association or corporation, involving more than one lease are filed at the same time for approval, one request for approval and one showing as to the qualifications of the assignee shall be sufficient.
(a) When an assignment is made of all the record title to a portion of the acreage in a lease, the assigned and retained portions become segregated into separate and distinct leases. In such a case, the assignee becomes a lessee of the Government as to the segregated tract that is the subject of assignment, and is bound by the terms of the lease as though the lease had been obtained from the United States in the assignee's own name, and the assignment, after its approval, shall be the basis of a new record. Royalty, minimum royalty and rental provisions of the original lease shall apply separately to each segregated portion.
(b) For assignments of a portion of an oil and gas lease approved after the effective date of ths section, each segregated lease shall continue in full force and effect for the primary term of the original lease and so long thereafter as oil or gas is produced from that segregated portion of the leased area in paying quantities or drillng or well reworking operations as approved by the Secretary are conducted.
(c) For those assignments approved prior to the effective date of this section, each segregated lease shall continue in full force and effect for the primary term of the original lease and so long thereafter as oil and gas may be produced from the original leased area in paying quantities or drilling or well reworking operations, as approved by the Secretary, are conducted.
The term of a lease shall be extended beyond the primary term so long as drilling or well reworking operations are approved by the Secretary according to the conditions set forth in 30 CFR 250.180.
In accordance with an approved exploration plan or development and production plan, a lease may be maintained in force by directional wells drilled under the leased area from surface locations on adjacent or adjoining land not covered by the lease. In such circumstances, drilling shall be considered to have commenced on the leased area when drilling is commenced on the adjacent or adjoining land for the purpose of directional drilling under the leased area through any directional well surfaced on adjacent or adjoining land. Production, drillling or reworking of any such directional well shall be considered production or drilling or reworking operations on the leased area for all purposes of the lease.
If an oil and gas lessee makes compensatory payments and if the lease is not being maintained in force by other production of oil or gas in paying quantities or by other approved drilling or reworking operations, such payments shall be considered as the equivalent of
(a) A suspension may extend the term of a lease (see 30 CFR 250.171) with the extension being the length of time the suspension is in effect except as provided in paragraph (b) of this section.
(b) A Directed Suspension does not extend the lease term when the Regional Supervisor directs a suspension because of:
(1) Gross negligence; or (2) A willful violation of a provision of the lease or governing regulations.
(c) MMS may issue suspensions for a period of up to 5 years per suspension. The Regional Supervisor will set the length of the suspension based on the conditions of the individual case involved. MMS may grant consecutive suspensions. For more information on suspension of operations or production refer to the section under the heading “Suspensions” in 30 CFR part 250, subpart A.
A lease or any officially designated subdivision thereof may be surrendered by the record title holder by filing a written relinquishment, in triplicate, with the appropriate OCS office of the MMS. No filing fee is required. A relinquishment shall take effect on the date it is filed subject to the continued obligation of the lessee and the surety to make all payments due, including any accrued rentals, royalties and deferred bonuses and to abandon all wells and condition or remove all platforms and other facilities on the land to be relinquished to the satisfaction of the Director.
(a) Any nonproducing lease issued under the act may be cancelled by the authorized officer whenever the lessee fails to comply with any provision of the act or lease or applicable regulations, if such failure to comply continues for 30 days after mailing of notice by registered or certified letter to the lease owner at the owner's record post office address. Any such cancellation is subject to judicial review as provided in section 23(b) of the Act.
(b) Producing leases issued under the Act may be cancelled by the Secretary whenever the lessee fails to comply with any provision of the Act, applicable regulations or the lease only after judicial proceedings as prescribed by section 5(d) of the Act.
(c) Any lease issued under the Act, whether producing or not, shall be canceled by the authorized officer upon proof that it was obtained by fraud or misrepresentation, and after notice and opportunity to be heard has been afforded to the lessee.
(d) Pursuant to section 5(a) of the Act, the Secretary may cancel a lease when:
(1) Continued activity pursuant to such lease would probably cause serious harm or damage to life, property, any mineral, national security or defense, or to the marine, coastal or human environment;
(2) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(3) The advantages of cancellation outweigh the advantages of continuing such lease or permit in force. Procedures and conditions contained in 30 CFR 250.182 shall apply as appropriate.
(a) All regulations in this part, insofar as they are applicable, shall supersede the provisions of any lease which is maintained under section 6(a) of the Act. However, the provisions of a lease relating to area, minerals, rentals, royalties (subject to sections 6(a) (8) and (9) of the Act), and term (subject to section 6(a)(10) of the Act and, as to
(b) A lease maintained under section 6(a) of the Act shall also be subject to all operating and conservation regulations applicable to the OCS. In addition, the regulations relating to geophysical and geological exploratory operations and to pipeline rights-of-way are applicable, to the extent that those regulations are not contrary to or inconsistent with the lease provisions relating to area, the minerals, rentals, royalties and term. The lessee shall comply with any provision of the lease as validated, the subject matter of which is not covered in the regulations in this part.
The existence of a lease that meets the requirements of section 6(a) of the Act shall not preclude the issuance of other leases of the same area for deposits of other minerals. However, no other lease of minerals shall authorize or permit the lessee thereunder unreasonably to interfere with or endanger operations under the existing lease. No sulphur leases shall be granted by the United States on any area while such area is included in a lease covering sulphur under section 6(b) of the Act.
(a) The Director shall conduct a study of any area or region included in any lease sale in order to establish information needed for assessment and management of impacts on the human, marine and coastal environments which may be affected by OCS oil and gas activities in such area or region. Any study shall, to the extent practicable, be designed to predict environmental impacts of pollutants introduced into the environments and of the impacts of offshore activities on the seabed and affected coastal areas.
(b) Studies shall be planned and carried out in cooperation with the affected States and interested parties and, to the extent possible, shall not duplicate studies done under other laws. Where appropriate, the Director shall, to the maximum extent practicable, enter into agreements with the National Oceanic and Atmospheric Administration in executing the environmental studies responsibilities. By agreement, the Director may also utilize services, personnel or facilities of any Federal, State or local government agency in the conduct of such study.
(c) Any study of an area or region required by paragraph (a) of this section for a lease sale shall be commenced not later than six months prior to holding a lease sale for that area. The Director may utilize information collected in any prior study. The Director may initiate studies for areas or regions not identified in the leasing program.
(d) After the leasing and developing of any area or region, the Director shall conduct such studies as are deemed necessary to establish additional information and shall monitor the human, marine and coastal environments of such area or region in a manner designed to provide information which can be compared with the results of studies conducted prior to OCS oil and gas development. This shall be done to identify any significant changes in the quality and productivity of such environments, to establish trends in the areas studies, and to design experiments identifying the causes of such changes. Findings from such studies shall be used to recommend modifications in practices which are employed to mitigate the effects of OCS activities and to enhance the data/information base for predicting impacts which might result from a single lease sale or cumulative OCS activities.
(e) Information available or collected by the studies program shall, to the extent practicable, be provided in a form and in a timeframe that can be used in the decision-making process associated with a specific leasing action or with longer term OCS minerals management responsibilities.
The following bid is submitted for an oil and gas lease on the area of the Outer Continental Shelf specified below:
Pub. L. 83-212, 67 Stat. 462, 43 U.S.C. 1331
The purpose of this part 259 is to define various terms appearing in parts 260, 261 and 262 of this chapter.
For purposes of parts 260, 261, and 262 of this chapter:
43 U.S.C. 1331 and 1337.
The purpose of this part 260 is to implement OCSLA, 43 U.S.C. 1331
For purposes of this part 260:
(a) This subpart establishes the several bidding systems that may be utilized in connection with the offering and sale of Federal leases for the exploration, development and production of oil and gas resources located on the OCS.
(b) Only bidding systems established by his subpart shall be utilized in OCS lease sales.
For purposes of this subpart B—
(a) A single bidding system selected from those listed in this paragraph shall be applied to each tract included in an OCS lease sale.
(1)
(ii) The amount of cash bonus to be paid is determined by the qualified bidder submitting the bid. Any deferment and the schedule of payments shall be included in the notice of OCS lease sale published in the
(iii) The annual rental to be paid by the highest responsible qualified bidder and any amounts creditable against future royalties shall be specified in the notice of sale published in the
(2)
(ii) The cash bonus to be paid by the highest responsible qualified bidder shall be an amount specified in the notice of OCS lease sale published in the
(iii) Rental payment amounts must be as specified in paragraph (a)(1)(iii) of this section.
(3)
(B) The royalty rate shall not be less than 12
(C)
(
(
(
(ii) The amount of cash bonus to be paid is determined by the qualified bidder submitting the bid. Any deferment and the schedule of payments shall be included in the notice of OCS lease sale published in the
(iii) Rental payment amounts must be as specified in paragraph (a)(1)(iii) of this section.
(4)
(A)
(2) The capital recovery factor needed to calculate the allowance for capital recovery, in accordance with § 220.020, shall be specified in the notice of OCS lease sale published in the
(B)
(ii) The amount of cash bonus to be paid is determined by the person submitting the bid. Any deferment and the schedule of payments shall be included in the notice of OCS lease sale published in the
(iii) The annual rental to be paid by the person awarded the lease shall be the amount specified in the notice of OCS lease sale published in the
(5)
(i) The royalty rate due on production may be less than 12
(ii) The amount and the procedure for payment of a cash bonus must be as specified in paragraph (a)(1)(ii) of this section.
(iii) Rental payment amounts must be as specified in paragraph (a)(1)(iii) of this section.
(6)
(i) The royalty due on production shall be specified as a percentage of the amount or value of the production saved, removed, or sold. When the value of production is used, by unit or in aggregate, the royalty rate will be determined based on prices for oil and/or gas as specified in the notice of sale published in the
(A) The lessee must calculate the royalty due using the formula or schedule specified in the lease based on the adjusted amount or indexed value of the oil and gas produced. The formula
(B) The royalty rate formula or schedule and the suspension or deferral magnitudes or formulas shall be specified in the notice of sale published in the
(C)
(
(
(
(
(ii) The amount and the procedure for payment of a cash bonus must be as specified in paragraph (a)(1)(ii) of this section.
(iii) Rental payment amounts must be as specified in paragraph (a)(1)(iii) of this section.
(7)
(i) Except for a period of suspension, the royalty rate due on production will be specified as a percentage of the amount or value of the production saved, removed, or sold. The applicable royalty rate shall be specified in the notice of the lease sale published in the
(A) The lessee must calculate the royalty due using the formula or schedule specified in the lease agreement based on the adjusted amount or indexed value of the oil and gas produced. The formula or schedule will describe the relationship between adjusted or actual amount of production, indexed value, or indexed price, and the royalty rate. It will stipulate the lowest and highest royalty rates that may apply.
(B) The formula or schedule for royalty due on production and the suspension magnitudes or formulas shall be specified in the notice of sale published in the
(ii) The amount and the procedure for payment of a cash bonus must be as specified in paragraph (a)(1)(ii) of this section.
(iii) Rental payment amounts must be as specified in paragraph (a)(1)(iii) of this section.
(b) The value basis for determining the actual value of production and for purposes of computing royalty in accordance with the bidding systems established by paragraph (a) of this section shall be as described in 30 CFR 206.102, 206.152, and 206.153;
(c) MMS may, by rule, add to or modify the bidding systems listed in paragraph (a) of this section, in accordance with the procedural requirements of OCSLA, 43 U.S.C. 1331
(d) This paragraph explains how the royalty-suspension volumes in section 304 of the Outer Continental Shelf Deep Water Royalty Relief Act, Public Law 104-58, apply to
(1) Your
(2) We will assign your lease to an existing field or designate a new field and will notify you and other affected lessees of that assignment. Within 15 days of that notification, you or any of the other affected lessees may file a written request with the Director, MMS, for reconsideration accompanied by a statement of reasons. The Director will respond in writing either affirming or reversing the assignment decision. The Director's decision is final for the Department and is not subject to appeal to the Interior Board of Land Appeals under 30 CFR part 290 and 43 CFR part 4.
(3) The Final Notice of Sale will specify the water depth for each
(i) 17.5 million barrels of oil equivalent (MMBOE) in 200 to 400 meters of water;
(ii) 52.5 MMBOE in 400 to 800 meters of water; and
(iii) 87.5 MMBOE in more than 800 meters of water.
(4) When production (other than test production) first occurs from any of the
(5) If a new field consists of
(6) If your
(7) If a field consists of more than one
(8) If an
(9) If a pre-Act lease(s) receives a royalty-suspension volume under 30 CFR part 203 for a field that already has a royalty-suspension volume due to
(10) A royalty-suspension volume will continue through the end of the month in which cumulative production from leases in a field entitled to share the royalty-suspension volume reaches that volume.
(11) If we reassign a well on an
(12) You may receive a royalty-suspension volume only if your entire lease is west of 87 degrees, 30 minutes West longitude. A field that lies on both sides of this meridian will receive a royalty-suspension volume only for those
(13) Your lease may obtain more than one royalty-suspension volume. If a new field is discovered on your
(14) You must measure natural gas production subject to the royalty-suspension volume as follows: 5.62 thousand cubic feet of natural gas, measured in accordance with 30 CFR part 250, subpart L, equals one barrel of oil equivalent.
(a) In analyzing the application of one of the bidding systems listed in § 260.110(a) to tracts selected for any OCS lease sale, MMS may, in its discretion, consider the following purposes and policies, recognizing that each of the purposes and policies may not be specifically applicable to the selection process for a particular bidding system and tract or may present a conflict that will have to be resolved in the process of bidding system selection, and that the order of listing does not denote a ranking:
(1) Providing fair return to the Federal Government;
(2) Increasing competition;
(3) Assuring competent and safe operations;
(4) Avoiding undue speculation;
(5) Avoiding unnecessary delays in exploration, development, and production;
(6) Discovering and recovering oil and gas;
(7) Developing new oil and gas resources in an efficient and timely manner;
(8) Limiting administrative burdens on Government and industry; and
(9) Providing an opportunity to experiment with various bidding systems to enable the identification of those that are the most appropriate for the satisfaction of the objectives of the United States in OCS lease sales.
(b) In performing the analysis referred to in paragraph (a), MMS may, in its discretion, take into account the following in relation to their impact upon the purposes and policies enumerated in paragraph (a) of this section.
(c) The bidding systems listed in § 260.110(a) (2) and (3) shall be applied to not less than 20 per centum and not more than 60 per centum of the total area offered for leasing each year during the five-year period commencing on September 18, 1978, unless DOI determines that the maximum and minimum per centum limitations set forth in this section are inconsistent with the purposes and policies of the OCSLA.
The purpose of the regulations in this subpart D is to encourage participation in OCS oil and gas lease sales by limiting the requirement for filing Statements of Production to certain joint bidders.
For purposes of this subpart D, all the terms used shall be defined as in 30 CFR 256.38.
(a) Any person who submits a joint bid for any OCS oil and gas lease during a six-month bidding period and who was chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas equivalents, and liquefied petroleum products, shall have filed a Statement of Production with the Director, MMS, in accordance with the requirements of 30 CFR 256.38. The Statement of Production shall state that the person filing the Statement is chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas equivalents, and liquefied petroleum products.
(b) No person chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas equivalents, and liquefied petroleum products may submit a joint bid for any OCS oil and gas lease during the applicable six-month bidding period with any other person similarly chargeable. Such bids shall be disqualified and rejected.
(c) No person may submit any bid during the applicable six-month bidding period pursuant to any agreement, the terms of which would result in two or more persons, each chargeable for the prior production period with an average daily production in excess of 1.6 million barrels of crude oil, natural gas equivalents, and liquefied petroleum products, acquiring or holding any interest in the tract for which the bid is submitted. Such bids shall be disqualified and rejected.
Sec. 604, Pub. L. 95-372, 92 Stat. 695 (43 U.S.C. 1863).
The purpose of this part is to implement the provisions of section 604 of the OCSLA of 1978 which provides that “no person shall, on the grounds of race, creed, color, national origin, or sex, be excluded from receiving or participating in any activity, sale, or employment, conducted pursuant to the provisions of . . . the Outer Continental Shelf Lands Act.”
This part applies to any contract or subcontract entered into by a lessee or by a contractor or subcontractor of a lessee after the effective date of these regulations to provide goods, services, facilities, or property in an amount of $10,000 or more in connection with any activity related to the exploration for or development and production of oil, gas, or other minerals or materials in the OCS under the Act.
As used in this part, the following terms shall have the meanings given below:
No contract or subcontract to which this part applies shall be denied to or withheld from any person on the grounds of race, creed, color, national origin, or sex.
(a) Whenever any person believes that he or she has been denied a contract or subcontract to which this part applies on the grounds of race, creed, color, national origin, or sex, such person may complain of such denial or withholding to the Regional Director of the OCS Region in which such action is alleged to have occurred. Any complaint filed under this part must be submitted in writing to the appropriate Regional Director not later than 180 days after the date of the alleged unlawful denial of a contract or subcontract which is the basis of the complaint.
(b) The complaint referred to in paragraph (a) of this section shall be accompanied by such evidence as may be available to a person and which is relevant to the complaint including affidavits and other documents.
(c) Whenever any person files a complaint under this part, the Regional Director with whom such complaint is filed shall give written notice of such filing to all persons cited in the complaint no later than 10 days after receipt of such complaint. Such notice shall include a statement describing the alleged incident of discrimination, including the date and the names of persons involved in it.
Whenever a Regional Director determines on the basis of any information, including that which may be obtained under § 270.5 of this title, that a violation of or failure to comply with any provision of this subpart probably occurred, the Regional director shall undertake to afford the complainant and the person(s) alleged to have violated the provisions of this part an opportunity to engage in informal consultations, meetings, or any other form of communications for the purpose of resolving the complaint. In the event such communications or consultations result in a mutually satisfactory resolution of the complaint, the complainant and all persons cited in the complaint shall notify the Regional Director in writing of their agreement to such resolution. If either the complainant or the person(s) alleged to have wrongfully discriminated fail to provide such written notice within a reasonable period of time, the Regional Director shall proceed in accordance with the provisions of §§ 250.500, 250.501, 250.502, and 250.510 of this title.
In addition to the penalties available under 30 CFR part 250, subpart N of this title, the Director may invoke any other remedies available to him or her under the Act or regulations for the lessee's failure to comply with provisions of the Act, regulations, or lease.
43 U.S.C. 1331
The information collection requirements contained in part 280 have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501
Section 5(a) of the Act (43 U.S.C. 1334(a)(1)) states that the Secretary “* * * shall prescribe such rules and regulations * * * necessary to carry out * * *” the provisions of the Act. The primary purpose of the regulations in this part is to prescribe policies, procedures, and requirements for conducting data and information-gathering activities associated with geological and geophysical (G&G) prospecting and scientific research in the OCS for minerals other than oil, gas, and sulphur. The regulations in this part do not apply to activities authorized under a mineral lease. Activities authorized under the regulations in this part do not give rise to any rights or interests in any OCS mineral discovered as a result of approved prospecting or scientific research activities.
When used in this part, the following terms shall have the meaning given below:
(a) No prospecting activities shall be conducted in the OCS without a permit approved by the Director pursuant to this part, unless such activities are being conducted pursuant to authority contained in a lease issued or maintained under part 256 or part 281 of this title or unless such activities are conducted by a Federal Agency.
(b) No person may conduct G&G scientific research activities in the OCS without a permit approved by the Director pursuant to this part if the proposed activities include either: (1) The drilling of a borehole to a depth greater than 300 feet below the seafloor; or (2) the use of solid or liquid explosives.
(c) Any person may conduct G&G scientific research in the OCS without obtaining a permit pursuant to this part if—
(1) The activities will not interfere with or endanger operations under any lease or right-of-way maintained or issued pursuant to the Act;
(2) The activities will not be unduly harmful to aquatic life in the area; result in pollution; create hazardous or unsafe conditions; unreasonably interfere with other uses of the area; or disturb any site, structure, or object of historical or archaeological significance; and
(3) The person conducting the activities or operating the vessel from which the activities are to be conducted has consulted and coordinated the conduct of those activities with any other users of the area.
(d) The Director may orally approve plan revisions or issue emergency permits to accommodate unforeseen or special circumstances. Oral approvals given for a written application shall be followed with a written confirmation by MMS. In the event an oral approval is given in response to an oral request, the applicant shall confirm the oral request in writing within 72 hours of the approval.
Permits approved under this part shall be granted for a term not to exceed 3 years. The Director may extend the term of a permit for an additional period(s) of time not to exceed a total of 2 years when the Director determines that the additional time is appropriate based upon a showing of good cause by the permittee.
(a) An application for a prospecting or scientific research permit shall be submitted to the Director at least 60 days prior to the date proposed as the startup date for activities in the permit area.
(b)(1) An application for a prospecting permit shall be submitted in a form and manner approved by the Director. Three copies of each application shall be submitted and shall include—
(i) The name, address, and nationality of the person(s) submitting the application;
(ii) The name, address, and telephone number of the person(s) directly responsible for conducting the activities proposed;
(iii) A description and a map of the area(s) covered by the application;
(iv) The period of time to be covered by the primary term of the permit not to exceed 3 years;
(v) A narrative description in nonproprietary terms of the activities to be conducted, such as mapping, geophysical surveying, drilling, bottom sampling, and dredging;
(vi) A detailed description and schedule giving the estimated starting and completion dates for the proposed activities that are to be authorized under the permit; and
(vii) A prospecting plan.
(2) An applicant for a prospecting permit shall indicate which data and information included in the application and plan the applicant considers proprietary.
(c) Upon application submitted by a permittee pursuant to this section, the Director may approve the conversion of a permit issued under part 251 of this title to a permit issued under this part. A permit issued under part 251, which is converted to a permit issued under this part, shall be subject to all the requirements of this part.
(d) An application for a permit to conduct scientific research activities shall be submitted in a form approved by the Director. The application should be signed by an officer of the organization proposing to carry out the activity and shall state—
(1) The name of the person conducting the proposed research;
(2) The type of research activity and manner in which it will be conducted;
(3) The location designated on a map, plat, or chart where the research activity will be conducted;
(4) A schedule indicating the starting and completion dates for each proposed scientific research activity;
(5) The proposed time and manner in which the information and data resulting from the research will be made available to the public for inspection
(6) An agreement that the information and data resulting from the scientific research activity will not be sold or withheld for exclusive use;
(7) The name, registry number, registered owner, and port of registry of vessels used in the operation; and
(8) A scientific research plan.
(e) Within 30 days following the receipt of an application for a permit and the accompanying plan which does not require preparation of an environmental analysis the Director shall—
(1) Approve the application and plan;
(2) Require the applicant to modify the application and/or plan; or
(3) Disapprove the application and plan. If the Director disapproves an application and plan, the statement of rejection shall give the reasons for the disapproval and shall advise the applicant of the changes needed to obtain approval.
(a) The applicant shall submit a plan with its application for a prospecting or scientific research permit. The plan shall include—
(1) Identification of the mineral(s) or material(s) of primary interest, if appropriate;
(2) A detailed description of the activities to be conducted;
(3) The type(s) of equipment to be used with special attention to safety and pollution prevention and control features and the name, registration, and mobile communication system of vessel(s);
(4) Maps showing location of proposed activities including drill holes, grab or basket samples, anticipated depth of penetration of drill holes, water depth, and location of proposed survey grids for each surveying method which is to be employed;
(5) A schedule indicating the starting and completion dates for each proposed activity;
(6) Anticipated environmental consequences of each proposed activity;
(7) Mitigation measures to be used to avoid or minimize adverse environmental impacts of proposed activities;
(8) For any activities which are to occur in an environmentally sensitive area, a plan for monitoring the effects of the activities on the environment;
(9) Any known archaeological resources in the area of the proposed activities; and
(10) Description of any potential conflicts with other uses or users in the permit area.
(b) If the penetration of one or more proposed drill holes will exceed 300 feet, the Director may require a drilling plan to be included as part of the plan before a permit is issued.
(c) If all needed information is not available at the time the plan is submitted, a plan shall indicate when the needed information will be obtained and submitted. In such a case, depending on the significance of the missing information, the Director may disapprove the plan, approve the plan based on the information submitted, or approve the plan with a specific condition that certain specified activities are not authorized and shall not be conducted until additional information is obtained and submitted for evaluation, and the Director gives specific approval to proceed with those activities.
(a) Activities authorized under a prospecting or scientific research permit issued under this part or research authorized pursuant to the provisions of § 280.5(c) of this part shall be conducted so as not to create conditions which will pose an unreasonable risk of—
(1) Interference with, or endangerment of, operations under any lease or permit issued or maintained pursuant to the Act;
(2) Serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life) or to the marine, coastal, or human environment;
(3) Serious, irreparable, or immediate harm or damage to property or to any mineral (in areas leased or not leased);
(4) Pollution;
(5) Disturbance of archaeological resources;
(6) Hazardous or unsafe conditions; or
(7) Interference with or serious, irreparable, or immediate harm to other uses of the area.
(b) The permittee or scientific researcher shall allow the Director to be present on any cruise.
(c) The permittee shall notify and obtain the prior approval of the Director before a substantial change from the approved plan is initiated.
(a) The permittee shall submit a status report to the Director within 30 days of the close of each calendar quarter or more frequently if requested by the Director. The report shall include a summary of the prospecting or scientific research activities conducted prior to the end of the reporting period and the results obtained. The last quarterly report may be combined with the final report if the final report is submitted within 30 days after the end of the last quarter in which permitted activity occurs. Each permittee shall submit to the Director a final report of activities conducted under the permit within 6 months after expiration of the permit or after the completion of prospecting or scientific research activities, or 60 days prior to a planned lease offering when prospecting or scientific research activities are within the planned leasing area, whichever is sooner, provided that no report shall be required less than 30 days after completion of permitted activities. The report shall include—
(1) A description of the work performed;
(2) Charts, maps, or plats depicting the area and blocks in which any activities were conducted specifically, identifying the lines of geophysical traverses and/or the locations where geological activity was conducted;
(3) The dates on which the actual activities were performed;
(4) A narrative summary of any mineral occurrences encountered including location, environmental features, and the nature and degree of adverse effects, if any, of the permitted activities on the environment, aquatic life, archaeological resources, or other uses of the area in which the activities were conducted;
(5) A report of the results of the environmental monitoring required in § 280.6(a)(8) of this part; and
(6) Such other descriptions of the activities conducted as may be specified by the Director.
(b) All persons shall immediately notify the Director of all serious accidents, any death or serious injury, or fire or explosion connected with any activity conducted pursuant to this part.
(a) Any permittee who acquires rock and mineral samples under a permit shall keep for 1 year after submittal of the final report a representative split of each geological sample and a quarter longitudinal segment of each core which shall be available for inspection at the convenience of the Director who may cut such core and geological samples for retention by MMS.
(b) Any permittee who acquires G&G data and information under a permit shall keep the data and information available for 3 years after submittal of the final report. The data and information shall be available for inspection and copying at a location within the appropriate OCS Region or at another location approved by the Director. The records shall include environmental data and information; G&G data and information; drill logs; analyses of cores, cuttings, and samples; and maps and navigation tapes showing the location where samples were taken and test drilling conducted.
The potential of proposed prospecting or scientific research activities for adverse impact on the environment will be evaluated by MMS to determine the need for mitigation measures. The MMS anticipates that activities of the type listed below typically will not cause significant environmental impact and, in accordance with 516 DM 6, Appendix 10 to the Departmental Manual, will normally be categorically excluded from additional environmental analysis. The types of activities include—
(a) Gravity and magnetometric observations and measurements;
(b) Bottom and subbottom acoustic profiling or imaging without the use of explosives;
(c) Mineral sampling of a limited nature such as that using either test drillholes or cores to less than 300 feet below the seafloor;
(d) Water and biotic sampling, if the sampling does not adversely affect shellfish beds, marine mammals, or an endangered species or if permitted by the National Marine Fisheries Service or another Federal Agency;
(e) Meteorological observations and measurements, including the setting of instruments;
(f) Hydrographic and oceanographic observations and measurements, including the setting of instruments;
(g) Sampling by box core or grab sampler to determine seabed geological or geotechnical properties;
(h) Television and still photographic observation and measurements;
(i) Shipboard mineral assaying and analysis; and
(j) Placement of positioning systems, including bottom transponders and surface and subsurface buoys reported in Notices to Mariners.
(a) The Governor(s) of adjacent State(s) shall be notified by the Director with a copy of the application for a permit with the accompanying plan immediately upon the submission of an application for approval.
(b) In cases where an environmental assessment is to be prepared, the Director will invite the Governor(s) of adjacent States(s) to review and provide comments regarding the proposed activities. The Director's invitation to provide comments shall allow the Governor a specified period of time to comment.
(c) The Director shall notify Federal Agencies, as appropriate, with a copy of the application for a permit with the accompanying plan immediately upon the submission of the application for approval.
(a) The Director shall make data, information, and samples available in accordance with the requirements and subject to the limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), and the implementing regulations.
(b) For geological data, information, and samples and geophysical information submitted under a permit and retained by MMS, the Director shall make such data, information, and samples available to the public 25 years after the date of submission of the data and information or such earlier time as may be agreed to by the permittee who provides the data or information. Geophysical data submitted under a permit and retained by MMS shall be made available to the public by the Director 50 years after the date of submission to MMS unless an earlier date is agreed to by the permittee who submits the data.
(c) The Director reserves the right to disclose any data, information, or samples submitted by a permittee to an independent contractor or agent for the purpose of reproducing, processing, reprocessing, or interpreting the data or information. Such contractor or agent shall be subject to the same limitations on disclosure of data, information, and samples as those applicable to the Director under paragraph (b) of this section.
(a) Proprietary data, information, and samples submitted to MMS by permittees shall be made available to adjacent State(s) upon request by the Governor(s) in accordance with paragraphs (b), (c), and (d) of this section.
(b) Disclosure shall occur only after the Governor has entered into an agreement with the Secretary providing that—
(1) The confidentiality of the information shall be maintained;
(2) In any action commenced against the Federal Government or the State for the failure to protect the confidentiality of proprietary information, the Federal Government or the State, as the case may be, may not raise as a defense any claim of sovereign immunity or any claim that the employee who revealed the proprietary information, which is the basis of the suit, was acting outside the scope of the person's employment in revealing the information;
(3) The State agrees to hold the United States harmless for any violation by the State or its employees or contractors of the agreement to protect the confidentiality of proprietary data and information and samples; and
(4) The materials containing the proprietary data, information, and samples shall remain the property of the United States.
(c) The data, information, and samples available to the State(s) pursuant to an agreement shall be related to leased lands.
(d) The materials containing the proprietary data, information, and samples shall be returned to MMS when they are no longer needed by the State or when requested by the Director.
The Director may suspend or temporarily prohibit the conduct of G&G prospecting or scientific research activities by notifying the person conducting the activity, either orally or in writing, when the Director determines that there is a threat of serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, any mineral (in areas leased or not leased), the national security or defense, or the marine, coastal, or human environment; or there is a failure to comply with a provision of the Act or of any applicable law, the provisions of the permit, or provisions of these and other applicable regulations. Such suspension or temporary prohibition shall be effective immediately upon receipt of the notice. Suspensions or temporary prohibitions issued orally shall be followed by a written notice confirming the action, and all written notices will be sent by certified or registered mail. A suspension or temporary prohibition shall remain in effect until the basis for the suspension or temporary prohibition has been corrected to the satisfaction of the Director.
The Director may cancel or a permittee may relinquish, in whole or in part, a permit to conduct prospecting or scientific research activities at any time by sending a notice of cancellation or a notice of relinquishment. Such notices shall state the reason for the cancellation or relinquishment and shall be sent by certified or registered mail to the other party at least 30 days in advance of the date that the cancellation or relinquishment will be effective.
Persons conducting activities in the OCS pursuant to this part shall be subject to the remedies and penalties provisions of section 24 of the Act and the applicable civil penalty procedures contained in part 250 of this title for noncompliance with any provision of the Act, permit, regulation, or order issued under the Act. The remedies or penalties prescribed in this section shall be in addition to any other penalty afforded by any other law or regulation.
Orders or decisions issued under the regulations in this part may be appealed as provided in part 290 of this title.
43 U.S.C. 1331
The information collection requirements contained in part 281 have been approved by the Office of Management and Budget under 44 U.S.C. 3507 and assigned clearance number 1010-0082. The information is being collected to determine if the applicant for a lease on the Outer Continental Shelf (OCS) is qualified to hold such a lease or to determine if a requested action is warranted. The information will be used to make those determinations. The obligation to respond is mandatory.
The purpose of these regulations is to establish procedures under which the Secretary of the Interior (Secretary) will exercise the authority granted to administer a leasing program for minerals other than oil, gas, and sulphur in the OCS. The rules in this part apply exclusively to leasing activities for minerals other than oil, gas, and sulphur in the OCS pursuant to the Act.
The Act authorizes the Secretary to grant leases for any mineral other than oil, gas, and sulphur in any area of the OCS to the qualified persons offering the highest cash bonuses on the basis of competitive bidding upon such royalty, rental, and other terms and conditions as the Secretary may prescribe at the time of offering the area for lease (43 U.S.C. 1337(k)). The Secretary is to administer the leasing provisions of the Act and prescribe the rules and regulations necessary to carry out those provisions (43 U.S.C. 1334(a)).
When used in this part, the following terms shall have the meaning given below:
(1) That is, or is proposed to be, receiving for processing, refining, or transshipping OCS mineral resources commercially recovered from the seabed;
(2) That is used, or is scheduled to be used, as a support base for prospecting, exploration, testing, and mining activities; or
(3) In which there is a reasonable probability of significant effect on land or water uses from such activity.
(a) In accordance with section 8(k) of the Act, leases shall be awarded only to qualified persons offering the highest cash bonus bid.
(b) Mineral leases issued pursuant to section 8 of the Act may be held only by:
(1) Citizens and nationals of the United States;
(2) Aliens lawfully admitted for permanent residence in the United States as defined in 8 U.S.C. 1101(a)(20);
(3) Private, public, or municipal corporations organized under the laws of the United States or of any State or of the District of Columbia or territory thereof; or
(4) Associations of such citizens, nationals, resident aliens, or private, public, or municipal corporations, States, or political subdivisions of States.
Under the provisions of 18 U.S.C. 1001, it is a crime punishable by up to 5 years imprisonment or a fine of $10,000, or both, for anyone knowingly and willfully to submit or cause to be submitted to any Agency of the United States any false or fraudulent statement(s) to any matters within the Agency's jurisdiction.
Any party adversely affected by a decision of an MMS official made pursuant to the provisions of this part shall have the right of appeal pursuant to part 290 of this title, except as provided otherwise in § 281.21 of this part.
The Secretary shall make data and information available to the public in accordance with the requirements and subject to the limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), and the implementing regulations (30 CFR parts 280 and 282 and 43 CFR part 2).
(a) Unless otherwise specified in the leasing notice, a lease for OCS minerals shall include rights to all minerals within the leased area except the following;
(1) Minerals subject to rights granted by existing leases;
(2) Oil;
(3) Gas;
(4) Sulphur;
(5) Minerals produced in direct association with oil, gas, or sulphur;
(6) Salt deposits which are identified in the leasing notice as being reserved;
(7) Sand and gravel deposits which are identified in the leasing notice as being reserved; and
(8) Source materials essential to production of fissionable materials which are reserved pursuant to section 12(a) of the Act.
(b) When an OCS mineral lease issued uner this part limits the minerals to which rights are granted, such lease shall include rights to minerals produced in direct association with the OCS mineral specified in the lease but not the rights to minerals specifically reserved.
(c) The existence of an OCS mineral, oil and gas, or sulphur lease shall not preclude the issuance of a lease(s) for other OCS minerals in the same area. However, no OCS mineral lease shall authorize or permit the lessee thereunder to unreasonably interfere with or endanger operations under an existing OCS mineral, oil and gas, or sulphur lease.
In the event of a controversy between the United States and a State as to whether certain lands are subject to Federal or State jurisdiction (43 U.S.C. 1336), either the Governor or the Secretary may initiate negotiations in an attempt to settle the jurisdictional controversy. With the concurrence of the Attorney General, the Secretary may enter into an agreement with a State with respect to OCS mineral activities under the Act or under State authority and to payment and impounding of rents, royalties, and other sums and with respect to the offering of lands for lease pending settlement of the controversy.
(a) Any person may at any time request that OCS minerals be offered for lease. A request that OCS minerals be offered for lease shall be submitted to the Director and shall contain the following information:
(1) The area to be offered for lease.
(2) The OCS minerals of primary interest.
(3) The available OCS mineral resource and environmental information pertaining to the area of interest to be offered for lease which supports the request.
(b) Within 45 days after receipt of a request submitted under paragraph (a) of this section, the Director shall either initiate steps leading to the offer of OCS minerals for lease and notify the applicant of the action taken or inform the applicant of the reasons for not initiating steps leading to the offer of OCS minerals for lease.
(c) Any interested party may at any time submit information to the Director concerning the scheduling of proposed lease sales of OCS minerals in any area of the OCS. Such information may include but not be limited to any of the following:
(1) Benefits of conducting a lease sale in an area.
(2) Costs of conducting a lease sale in an area.
(3) Geohazards which could be encountered in an area.
(4) Geological information about an area and mineral resource potential.
(5) Environmental information about an area.
(6) Information about known archaeological resources in an area.
(a) When considering whether to offer OCS minerals for lease, the Secretary, upon the Department of the Interior's own initiative or as a result of a submission under § 281.11, may request indications of interest in the leasing of a specific OCS mineral, a group of OCS minerals, or all OCS minerals in the area being considered for lease. Requests for information and interest
(b) States and local governments, industry, other Federal Agencies, and all interested parties (including the public) may respond to a request for information and interest. All information provided to the Secretary will be considered in the decision whether to proceed with additional steps leading to the offering of OCS minerals for lease.
(c) The Secretary may request specific information concerning the offering of a specific OCS mineral, a group of OCS minerals, or all OCS minerals in a broad area for lease or the offering of one or more discrete tracts which represent a minable orebody. The Secretary's request may ask for comments on OCS areas which have been determined to warrant special consideration and analysis. Requests may be for comments concerning geological conditions or archaeological resources on the seabed; multiple uses of the area proposed for leasing, including navigation, recreation and fisheries; and other socioeconomic, biological, and environmental information relating to the area proposed for leasing.
(a) The Secretary may invite the adjacent State Governor(s) to join in, or the adjacent State Governor(s) may request that the Secretary join in, the establishment of a State/Federal task force or some other joint planning or coordination arrangement when industry interest exists for OCS mineral leasing or geological information appears to support the leasing of OCS minerals in specific areas. Participation in joint State/Federal task forces or other arrangements will afford the adjacent State Governor(s) opportunity for access to available data and information about the area; knowledge of progress made in the leasing process and of the results of subsequent exploration and development activities; facilitate the resolution of issues of mutual interest; and provide a mechanism for planning, coordination, consultation, and other activities which the Secretary and the Governor(s) may identify as contributing to the leasing process.
(b) State/Federal task forces or other such arrangement are to be constituted pursuant to such terms and conditions (consistent with Federal law and these regulations) as the Secretary and the adjacent State Governor(s) may agree.
(c) State/Federal task forces or other such arrangements will provide a forum which the Secretary and adjacent State Governor(s) may use for planning, consultation, and coordination on concerns associated with the offering of OCS minerals other than oil, gas, or sulphur for lease.
(d) With respect to the activities authorized under these regulations each State/Federal task force may make recommendations to the Secretary and adjacent State Governor(s) concerning:
(1) The identification of areas in which OCS minerals might be offered for lease;
(2) The potential for conflicts between the exploration and development of OCS mineral resources, other users and uses of the area, and means for resolution or mitigation of these conflicts;
(3) The economic feasibility of developing OCS mineral resources in the area proposed for leasing;
(4) Potential environmental problems and measures that might be taken to mitigate these problems;
(5) Development of guidelines and procedures for safe, environmentally responsible exploration and development practices; and
(6) Other issues of concern to the Secretary and adjacent State Governor(s).
(e) State/Federal task forces or other such arrangements might also be used to conduct or oversee research, studies, or reports (e.g., Environmental Impact Statements).
The Secretary, after considering the available OCS mineral resources and environmental data and information, the recommendation of any joint State/Federal task force established pursuant to § 281.13 of this part, and the comments received from interested parties, shall select the tracts to be considered for offering for lease. The selected
The size of the tracts to be offered for lease shall be as determined by the Secretary and specified in the leasing notice. It is intended that tracts offered for lease be sufficiently large to include potentially minable OCS mineral orebodies. When the presence of any minable orebody is unknown and additional prospecting is needed to discover and delineate OCS minerals, the size of tracts specified in the leasing notice may be relatively large.
(a) Prior to offering OCS minerals in an area for lease, the Director shall assess the available information including recommendations of any joint State/Federal task force established pursuant to § 281.13 of this part to determine lease sale procedures to be prescribed and to develop a proposed leasing notice which sets out the proposed primary term of the OCS mineral leases to be offered; lease stipulations including measures to mitigate potentially adverse impacts on the environment; and such rental, royalty, and other terms and conditions as the Secretary may prescribe in the leasing notice.
(b) The proposed leasing notice shall be sent to the Governor(s) of any adjacent State(s), and a Notice of its availability shall be published in the
(c) Written comments of the adjacent State Governor(s) submitted within 60 days after publication of the Notice of Availability of the proposed leasing notice shall be considered by the Secretary.
(d) Prior to publication of the leasing notice, the Secretary shall respond in writing to the comments of the adjacent State Governor(s) stating the reasons for accepting or rejecting the Governor's recommendations, or for implementing any alternative mutually acceptable approach identified in consultation with the Governor(s) as a means to provide a reasonable balance between the national interest and the well being of the citizens of the adjacent State.
(a) The Director shall publish the leasing notice in the
(b) The leasing notice shall contain a reference to the OCS minerals lease form which shall be issued to successful bidders.
(c) The leasing notice shall specify the terms and conditions governing the payment of the winning bid.
(a) The OCS minerals shall be offered by competitive, cash bonus bidding under terms and conditions specified in the leasing notice and in accordance with all applicable laws and regulations.
(b)(1) When the leasing notice specifies the use of sealed bids, such bids received in response to the leasing notice shall be opened at the place, date, and time specified in the leasing notice. The sole purpose of opening bids is to publicly announce and record the bids received, and no bids shall be accepted or rejected at that time.
(2) The Secretary reserves the right to reject any and all sealed bids received for any tract, regardless of the amount offered.
(3) In the event the highest bids are tie bids when using sealed bidding procedures, the tied bidders may be permitted to submit oral bids to determine the highest cash bonus bidder.
(c)(1) When the leasing notice specifies the use of oral bids, oral bids shall be received at the place, time, and date and in accordance with the procedures specified in the leasing notice.
(2) The Secretary reserves the right to reject all oral bids received for any tract, regardless of the amount offered.
(d) When the leasing notice specifies the use of deferred cash bonus bidding, bids shall be received in accordance with paragraph (b) or (c) of this section, as appropriate. The high bid will be determined based upon the net present value of each total bid. The appropriate discount rate will be specified in the leasing notice. High bidders using the deferred bonus option shall pay a minimum of 20 percent of the cash bonus bid prior to lease issuance. At least a total of 60 percent of the cash bonus bid shall be due on or before the 5th anniversary of the lease, and payment of the remainder of the cash bonus bid shall be due on the 10th anniversary of the lease. The lessee shall submit a bond guaranteeing payment of the deferred portion of the bonus, in accordance with § 281.33.
An OCS mineral lease for OCS minerals other than sand and gravel shall be for a primary term of not less than 20 years as stipulated in the leasing notice. The primary lease term for each OCS mineral shall be determined based on exploration and development requirements for the OCS minerals being offered by the Secretary. An OCS mineral lease for sand and gravel shall be for a primary term of 10 years unless otherwise stipulated in the leasing notice. A lease will continue beyond the specified primary term for so long thereafter as leased OCS minerals are being produced in accordance with an approved mining operation or the lessee is otherwise in compliance with provisions of the lease and the regulations in this chapter under which a lessee can earn continuance of the OCS mineral lease in effect.
(a) If the bidder is an individual, a statement of citizenship shall accompany the bid.
(b) If the bidder is an association (including a partnership), the bid shall be accompanied by a certified statement indicating the State in which it is registered and that the association is authorized to hold mineral leases on the OCS, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations).
(c) If the bidder is a corporation, the bid shall be accompanied by the following information:
(1) Either a statement certified by the corporate Secretary or Assistant Secretary over the corporate seal showing the State in which it was incorporated and that it is authorized to hold mineral leases on the OCS or appropriate reference to statements or record previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations).
(2) Evidence of authority of persons signing to bind the corporation. Such evidence may be in the form of a certified copy of either the minutes of the board of directors or of the bylaws indicating that the person signing has authority to do so, or a certificate to that effect signed by the Secretary or Assistant Secretary of the corporation over the corporate seal, or appropriate reference to statements or records previously submitted to an MMS OCS office (including material submitted in compliance with prior regulations). Bidders are advised to keep their filings current.
(3) The bid shall be executed in conformance with corporate requirements.
(d) Bidders should be aware of the provisions of 18 U.S.C. 1860, which prohibits unlawful combination or intimidation of bidders.
(e) When sealed bidding is specified in the leasing notice, a separate sealed bid shall be submitted for each bid unit that is bid upon as described in the leasing notice. A bid may not be submitted for less than a bidding unit identified in the leasing notice.
(f) When oral bidding is specified in the leasing notice, information which must accompany a bid pursuant to paragraph (a), (b), or (c) of this section,
(a)(1) The decision of the Director on bids shall be the final action of the Department, subject only to reconsideration by the Secretary, pursuant to a written request in accordance with paragraph (a)(2) of this section. The delegation of review authority to the Office of Hearings and Appeals shall not be applicable to decisions on high bids for leases in the OCS.
(2) Any bidder whose bid is rejected by the Director may file a written request for reconsideration with the Secretary within 15 days of notice of rejection, accompanied by a statement of reasons with a copy to the Director. The Secretary shall respond in writing either affirming or reversing the decision.
(b) Written notice of the Director's action in accepting or rejecting bids shall be transmitted promptly to those bidders whose deposits have been held. If a bid is accepted, such notice shall transmit three copies of the lease form to the successful bidder. As provided in § 281.26 of this part, the bidder shall, not later than the 10th business day after receipt of the lease, execute the lease, pay the first year's rental, and unless payment of a portion of the bid is deferred, pay the balance of the bonus bid. When payment of a portion of the bid is deferred, the successful bidder shall also file a bond to guarantee payment of the deferred portion as required in § 281.33. Deposits shall be refunded on high bids subsequently rejected. When three copies of the lease have been executed by the successful bidder and returned to the Director, the lease shall be executed on behalf of the United States; and one fully executed copy shall be transmitted to the successful bidder.
(c) If the successful bidder fails to execute the lease within the prescribed time or to otherwise comply with the applicable regulations, the successful bidder's deposit shall be forfeited and disposed of in the same manner as other receipts under the Act.
(d) If, before the lease is executed on behalf of the United States, the land which would be subject to the lease is withdrawn or restricted from leasing, the deposit shall be refunded.
(e) If the awarded lease is executed by an agent acting on behalf of the bidder, the bidder shall submit with the executed lease, evidence that the agent is authorized to act on behalf of the bidder.
The OCS mineral leases shall be issued on the lease form prescribed by the Secretary in the leasing notice.
Leases issued under the regulations in this part shall be dated and become effective as of the first day of the month following the date leases are signed on behalf of the lessor except that, upon written request, a lease may be dated and become effective as of the first day of the month within which it is signed on behalf of the lessor.
(a) For sealed bids, a bonus bid deposit of a specified percentage of the total amount bid is required to be submitted with the bid. The percentage of bonus bid required to be deposited will be specified in the leasing notice. The remittance may be made in cash or by Federal Reserve check, commerical check, bank draft, money order, certified check, or cashier's check made payable to “Department of the Interior—MMS.” Payment of this portion of the bonus bid may not be made by Electronic Funds Transfer.
(b) For oral bids, a bonus bid deposit of a specified percentage of the total amount bid must be submitted to the official designated in the leasing notice following the completion of the oral bidding. The percentage of bonus bid required to be deposited will be specified in the leasing notice. Payment of this portion of the bonus bid shall be made by Electronic Fund Transfer within the timeframe specified in the leasing notice.
(c) The deposit received from high bidders will be placed in a Treasury account pending acceptance or rejection of the bid. Other bids submitted under
(d) The balance of the winning bonus bid and all rentals and royalties must be paid in accordance with the terms and conditions of this part, the Leasing Notice, and Subchapter A of this chapter.
(e) For each lease issued pursuant to this subpart, there shall be one person identified who shall be solely responsible for all payments due and payable under the provisions of the lease. The single responsible person shall be designated as the payor for the lease and shall be so identified on the Solid Minerals Payor Information Form (MMS-4030) in accordance with § 210.201 of this title. The designated person shall be responsible for all bonus, rental, and royalty payments.
(f) Royalty shall be computed at the rate specified in the leasing notice, and paid in value unless the Secretary elects to have the royalty delivered in kind.
(g) For leases which provide for minimum royalty payments, each lessee shall pay the minimum royalty specified in the lease at the end of each lease year beginning with the lease year in which production royalty is paid (whether the full amount specified in the lease or
(h) Unless stated otherwise in the lease, product valuation will be in accordance with the regulations of this chapter. The value used in the computation of royalty shall be determined by the Director. The value, for royalty purposes, shall be the gross proceeds received by the lessee for produced substances at the point the product is produced and placed in its first marketable condition, consistent with prevailing practices in the industry. In establishing the value, the Director shall consider, in this order: (1) The price received by the lessee; (2) commodity and spot market transactions; (3) any other valuation method proposed by the lessee and approved by the Director; and (4) value or cost netback. For non-arm's length transactions, the first benchmark will only be accepted if it is not less than the second benchmark.
(i) All payors must submit payments and payment information forms and maintain auditable records in accordance with the following Royalty Management regulations of this title:
(a) The annual lease rental shall be due and payable in accordance with the provisions of this section. No rental shall be due or payable under a lease commencing with the first lease anniversary date following the commencement of royalty payments on leasehold production computed on the basis of the royalty rate specified in the lease except that annual rental shall be due for any year in which production from the leasehold is not subject to royalty pursuant to § 281.28.
(b) Unless otherwise specified in the leasing notice and subsequently issued lease, no annual rental payment shall be due during the first 5 years in the life of a lease.
(c) The leasee shall pay an annual rental in the amount specified in the leasing notice and subsequently issued lease not later than the last day prior to the commencement of the rental year.
(d) A rental adjustment schedule and amount may be specified in a leasing notice and subsequently issued lease when a variance is warranted by geologic, geographic, technical, or economic conditions.
(a) The royalty due the lessor on OCS minerals produced (i.e., sold, transferred, used, or otherwise disposed of) from a lease shall be set out in a separate schedule attached to and made a part of each lease and shall be as specified in the leasing notice. The royalty due on production shall be based on a percentage of the value or amount of the OCS mineral(s) produced, a sum assessed per unit of product, or other such method as the Secretary may prescribe in the leasing notice. When the royalty specified is a sum assessed per unit of product, the amount of the royalty shall be subject to an annual adjustment based on changes in the appropriate price index, when specified in the leasing notice. When the royalty is specified as a percentage of the value or amount of the OCS minerals produced, the Secretary will notify the lessee when and where royalty is to be delivered in kind.
(b) When prescribed in the leasing notice and subsequently issued lease, royalty due on OCS minerals produced from a leasehold will be reduced for up to any 5 consecutive years, as specified by the lessee prior to the commencement of production, during the 1st through 15th year in the life of the lease. No royalty shall be due in any year of the specified 5-year period that occurs during the 1st through 10th years in the life of the lease, and a royalty of one-half the amount specified in the lease shall be due in any year of the specified 5-year period that occurs in the 11th through 15th year in the life of the lease. The lessee shall pay the amount specified in the lease rental for any royalty free year. The minimum royalty specified in the lease shall apply during any year of reduced royalty.
The method of valuing the product from a leasehold shall be in accordance with regulations of this chapter and procedures prescribed in the leasing notice and subsequently issued lease.
Unless otherwise specified in the leasing notice, each lease issued pursuant to the regulations in this part shall require the payment of a specified minimum annual royalty beginning with the year in which OCS minerals are produced (sold, transferred, used, or otherwise disposed of) from the leasehold except that the annual rentals shall apply during any year that royalty free production is in effect pursuant to § 281.28(b). Minimum royalty payments shall be offset by royalty paid on production during the lease year. Minimum royalty payments are due at the beginning of the lease year and payable by the end of the month following the end of the lease year for which they are due.
(a) Subject to the approval of the Secretary, an overriding royalty interest may be created by an assignment pursuant to section 8(e) of the Act. The Secretary may deny approval of an assignment which creates an overriding royalty on a lease whenever that denial is determined to be in the interest of conservation, necessary to prevent premature abandonment of a producing mine, or to make possible the mining of economically marginal or low-grade ore deposits. In any case, the total of applicable overriding royalties may not exceed 2.5 percent or one-half the base royalty due the Federal Government, whichever is less.
(b) No transfer or agreement may be made which creates an overriding royalty interest unless the owner of that interest files an agreement in writing that such interest is subject to the limitations provided in § 281.30 of this part, paragraph (a) of this section, and § 281.32 of this part.
(a) The Secretary may waive, suspend, or reduce the rental, minimum royalty, and/or production royalty prescribed in a lease for a specified time period when the Secretary determines
(b) An application for waiver, suspension, or reduction of rental, minimum royalty, or production royalty under paragraph (a) of this section shall be filed in duplicate with the Director. The application shall contain the serial number(s) of the lease(s), the name of the lessee(s) of record, and the operator(s) if applicable. The application shall either:
(1)(i) Show the location and extent of all mining operations and a tabulated statement of the minerals mined and subject to royalty for each of the last 12 months immediately prior to filing the application:
(ii) Contain a detailed statement of expenses and costs of operating the lease, the income from the sale of any lease products, and the amount of all overriding royalties and payments out of production paid to others than the United States; and
(iii) All facts showing whether or not the mine(s) can be successfully operated under the royalty fixed in the lease; or
(2) If no production has occurred from the lease, show that the lease cannot be successfully operated under the rental, royalty, and other conditions specified in the lease.
(c) The applicant for a waiver, suspension, or reduction under this section shall file documentation that the lessee and the royalty holders agree to a reduction of all other royalties from the lease so that the aggregate of all other royalties does not exceed one-half the amount of the reduced royalties that would be paid to the United States.
(a) When the leasing notice specifies that payment of a portion of the bonus bid can be deferred, the lessee shall be required to submit a surety or personal bond to guarantee payment of a deferred portion of the bid. Upon the payment of the full amount of the cash bonus bid, the lessee's bond will be released.
(b) All bonds to guarantee payment of the deferred portion of the high cash bonus bid furnished by the lessee must be in a form or on a form approved by the Associate Director for Offshore Minerals Management. A single copy of the required form is to be executed by the principal or, in the case of surety bonds, by both the principal and an acceptable surety.
(1) Only those surety bonds issued by qualified surety companies approved by the Department of the Treasury shall be accepted. (See Department of the Treasury Circular No. 570 and any supplemental or replacement circulars.)
(2) Personal bonds shall be accompanied by a cashier's check, certified check, or negotiable U.S. Treasury bonds of an equal value to the amount specified in the bond. Negotiable Treasury bonds shall be accompanied by a proper conveyance of full authority to the Director to sell such securities in case of default in the performance of the terms and conditions of the lease.
(c) Prior to the commencement of any activity on a lease(s), the lessee shall submit a surety or personal bond as described in § 282.40 of this title. Prior to the approval of a Delineation, Testing, or Mining Plan, the bond amount shall be adjusted, if appropriate, to cover the operations and activities described in the proposed plan.
(a) Subject to the approval of the Secretary, a lease may be assigned, in whole or in part, pursuant to section 8(e) of the Act to anyone qualified to hold a lease.
(b) Any approved assignment shall be deemed to be effective on the first day of the lease month following the date that it is submitted to the Director for approval unless by written request the parties request that the effective date be the first of the month in which the Director approves the assignment.
(c) The assignor shall be liable for all obligations under the lease occurring prior to the effective date of an assignment.
(d) The assignee shall be liable for all obligations under the lease occurring on or after the effective date of an assignment and shall comply with all terms and conditions of the lease and applicable regulations issued under the Act.
(a)(1) All instruments of transfer of a lease or of an interest therein including subleases and assignments of record interest shall be filed in triplicate for approval within 90 days from the date of final execution. They shall include a statement over the transferee's own signature with respect to citizenship and qualifications similar to that required of a lessee and shall contain all of the terms and conditions agreed upon by the parties thereto.
(2) An application for approval of any instrument required to be filed shall not be accepted unless accompanied by a nonrefundable fee of $50. Any document not required to be filed by these regulations but submitted for record purposes shall be accompanied by a nonrefundable fee of $50 per lease affected. Such documents may be rejected at the discretion of the authorized officer.
(b) An attorney in fact signing on behalf of the holder of a lease or sublease, shall furnish evidence of authority to execute the assignment or application for approval and the statement required by § 281.20 of this part.
(c) Where an assignment creates separate leases, a bond shall be furnished for each of the resulting leases in the amount prescribed in § 282.40 of this title. Where an assignment does not create separate leases, the assignee, if the assignment so provides and the surety consents, may become a joint principal on the bond with the assignor.
(d) An heir or devisee of a deceased holder of a lease or any interest therein shall be recognized as the lawful successor to such lease or interest if evidence of status as an heir or devisee is furnished in the form of:
(1) A certified copy of an appropriate order or decree of the court having jurisdiction over the distribution of the estate, or
(2) If no court action is necessary, the statement of two disinterested persons having knowledge of the fact or a certified copy of the will.
(e) The heirs or devisee shall file statements that they are the persons named as successors to the estate with evidence of their qualifications to hold such lease or interest therein.
(f) In the event an heir or devisee is unable to qualify to hold the lease or interest, the heir or devisee shall be recognized as the lawful successor of the deceased and be entitled to hold the lease for a period not to exceed 2 years from the date of death of the predecessor in interest.
(g) Each obligation under any lease and under the regulations in this part shall inure to the heirs, executors, administrators, successors, or assignees of the lease.
(a) When an assignment is made of all the record title to a portion of the acreage in a lease, the assigned and retained portions of the lease area become segregated into separate and distinct leases. In such a case, the assignee becomes a lessee of the Government as to the segregated tract that is the subject of the assignment and is bound by the terms of the lease as though the lease had been obtained from the United States in the assignee's own name, and the assignment, after its approval, shall be the basis of a new record. Royalty, minimum royalty, and annual rental provisions of the lease shall apply separately to each segregated portion.
(b) Each lease of an OCS mineral created by the segregation of a lease under paragraph (a) of this section shall continue in full force and effect for the remainder of the primary term of the original lease and so long thereafter as minerals are produced from the portion of the lease created by segregation in accordance with operations approved by the Director or the lessee is otherwise in compliance with provisions of the lease or regulations for
(a) If the Director orders the suspension of either operations or production, or both, with respect to any lease in its primary term, the primary term of the lease shall be extended by a period of time equivalent to the period of the directed suspension.
(b) If the Director orders or approves the suspension of either operations or production, or both, with respect to any lease that is in force beyond its primary term, the term of the lease shall not be deemed to expire so long as the suspension remains in effect.
(a) A lease or any part thereof may be surrendered by the record title holder by filing a written relinquishment with the Director. A relinquishment shall take effect on the date it is filed subject to the continued obligation of the lessee and the surety to:
(1) Make all payments due, including any accrued rentals and royalties; and
(2) Abandon all operations, remove all facilities, and clear the land to be relinquished to the satisfaction of the Director.
(b) Upon relinquishment of a lease, the data and information submitted under the lease will no longer be held confidential and will be available to the public.
(a) Whenever the owner of a nonproducing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, and the default continues for a period of 30 days after mailing of notice by registered or certified letter to the lease owner at the owner's record post office address, the Secretary may cancel the lease pursuant to section 5(c) of the Act, and the lessee shall not be entitled to compensation. Any such cancellation is subject to judicial review as provided by section 23(b) of the Act.
(b) Whenever the owner of any producing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, the Secretary may cancel the lease only after judicial proceedings pursuant to section 5(d) of the Act, and the lessee shall not be entitled to compensation.
(c) Any lease issued under the Act, whether producing or not, may be canceled by the Secretary upon proof that it was obtained by fraud or misrepresentation and after notice and opportunity to be heard has been afforded to the lessee.
(d) The Secretary may cancel a lease in accordance with the following:
(1) Cancellation may occur at any time if the Secretary determines after a hearing that:
(i) Continued activity pursuant to such lease would probably cause serious harm or damage to life (including fish and other aquatic life), to property, to any mineral (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environment;
(ii) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(iii) The advantages of cancellation outweigh the advantages of continuing such lease in force;
(2) Cancellation shall not occur unless and until operations under such lease shall have been under suspension or temporary prohibition by the Secretary, with due extension of any lease term continuously for a period of 5 years, or for a lesser period upon request of the lessee; and
(3) Cancellation shall entitle the lessee to receive such compensation as is shown to the Secretary as being equal to the lesser of:
(i) The fair value of the canceled rights as of the date of cancellation, taking into account both anticipated revenues from the lease and anticipated costs, including costs of compliance with all applicable regulations and operating orders, liability for cleanup costs or damages, or both, and all other costs reasonably anticipated on the lease, or
(ii) The excess, if any, over the lessee's revenues from the lease (plus interest thereon from the date of receipt to date of reimbursement) of all consideration paid for the lease and all direct expenditures made by the lessee after the date of issuance of such lease and in connection with exploration or development, or both, pursuant to the lease (plus interest on such consideration and such expenditures from date of payment to date of reimbursement), except that in the case of joint leases which are canceled due to the failure of one or more partners to exercise due diligence, the innocent parties shall have the right to seek damages for such loss from the responsible party or parties and the right to acquire the interests of the negligent party or parties and be issued the lease in question.
(iii) The lessee shall not be entitled to compensation where one of the following circumstances exists when a lease is canceled:
(A) A producing lease is forfeited or is canceled pursuant to section (5)(d) of the Act;
(B) A Testing Plan or Mining Plan is disapproved because of the lessee's failure to demonstrate compliance with the requirements of applicable Federal Law; or
(C) The lessee(s) of a nonproducing lease fails to comply with a provision of the Act, the lease, or regulations issued under the Act, and the noncompliance continues for a period of 30 days or more after the mailing of a notice of noncompliance by registered or certified letter to the lessee(s).
43 U.S.C. 1331
The information collection requirements in this part have been approved by the Office of Management and Budget under 44 U.S.C. 3507 and assigned clearance number 1010-0081. The information is being collected to inform the Minerals Management Service (MMS) of general mining operations in the Outer Continental Shalf (OCS). The information will be used to ensure that operations are conducted in a safe and environmentally responsible manner in compliance with governing laws and
(a) The Act authorizes the Secretary to prescribe such rules and regulations as may be necessary to carry out the provisions of the Act (43 U.S.C. 1334). The Secretary is authorized to prescribe and amend regulations that the Secretary determines to be necessary and proper in order to provide for the prevention of waste, conservation of the natural resources of the OCS, and the protection of correlative rights therein. In the enforcement of safety, environmental, and conservation laws and regulations, the Secretary is authorized to cooperate with adjacent States and other Departments and Agencies of the Federal Government.
(b) Subject to the supervisory authority of the Secretary, and unless otherwise specified, the regulations in this part shall be administered by the Director of the MMS.
The rules and regulations in this part apply as of their effective date to all operations conducted under a mineral lease for OCS minerals other than oil, gas, or sulphur issued under the provisions of section 8(k) of the Act.
When used in this part, the following terms shall have the meaning given below:
(1) That is, or is proposed to be, receiving for processing, refining, or transshipment OCS mineral resources commercially recovered from the seabed;
(2) That is used, or is scheduled to be used, as a support base for prospecting, exploration, testing, or mining activities; or
(3) In which there is a reasonable probability of significant effect on land or water uses from such activity.
(1) Geophysical surveys where magnetic, gravity, seismic, or other systems are used to detect or imply the presence of minerals;
(2) Any drilling including the drilling of a borehole in which the discovery of a mineral other than oil, gas, or sulphur is made and the drilling of any additional boreholes needed to delineate any mineral deposits; and
(3) The taking of sample portions of a mineral deposit to enable the lessee to determine whether to proceed with development and production.
(a) In carrying out MMS's responsibilities under the Act and regulations in this part, the Director shall provide opportunities for Governors of adjacent States, State/Federal task forces, lessees and operators, other Federal Agencies, and other interested parties to review proposed activities described in a Delineation, Testing, or Mining Plan together with an analysis of potential impacts on the environment and to provide comments and recommendations for the disposition of the proposed plan.
(b)(1) For Delineation Plans, the adjacent State Governor(s) shall be notified by the Director within 15 days following the submission of a request for approval of a Delineation Plan. Notification shall include a copy of the proposed Delineation Plan and the accompanying environmental information. The adjacent State Governor(s) who
(2) In cases where an Environmental Assessment is to be prepared, the Director's invitation to provide comments may allow the adjacent State Governor(s) more than 30 days following receipt of the proposed plan to provide comments.
(3) The Director shall notify Federal Agencies, as appropriate, with a copy of the proposed Delineation Plan and the accompanying environmental information within 15 days following the submission of the request. Agencies that wish to comment on a proposed Delineation Plan shall do so within 30 days following receipt of the plan and the accompanying information.
(c)(1) For Testing Plans, the adjacent State Governor(s) shall be notified by the Director within 20 days following submission of a request for approval of a proposed Testing Plan. Notification shall include a copy of the proposed Testing Plan and the accompanying environmental information. The adjacent State Governor(s) who wishes to comment on a proposed Testing Plan may do so within 60 days of the receipt of a plan and the accompanying information.
(2) In cases where an EIS is to be prepared, the Director's invitation to provide comments may allow the adjacent State Governor(s) more than 60 days following receipt of the proposed plan to provide comments.
(3) The Director shall notify Federal Agencies, as appropriate, with a copy of the proposed Testing Plan and the accompanying environmental information within 20 days following the submission of the request. Agencies that wish to comment on a proposed Testing Plan shall do so within 60 days following receipt of the plan and the accompanying information.
(d)(1) For Mining Plans, the adjacent State Governor(s) shall be notified by the Director within 20 days following the submission of a request for approval of a proposed Mining Plan. Notification shall include a copy of the proposed Mining Plan and the accompanying environmental information. The adjacent State Governor(s) who wishes to comment on a proposed Mining Plan may do so within 60 days of the receipt of a plan and the accompanying information.
(2) In cases where an EIS is to be prepared, the Director's invitation to provide comments may allow the adjacent State Governor(s) more than 60 days following receipt of the proposed plan to provide comments.
(3) The Director shall notify Federal Agencies, as appropriate, with a copy of the proposed Mining Plan and the accompanying environmental information within 20 days following the submission of the request. Agencies that wish to comment on a proposed Mining Plan shall do so within 60 days following receipt of the plan and the accompanying information.
(e) When an adjacent State Governor(s) has provided comments pursuant to paragraphs (b), (c), and (d) of this section, the Governor(s) shall be given, in writing, a list of recommendations which are adopted and the reasons for rejecting any of the recommendations of the Governor(s) or for implementing any alternative means identified during consultations with the Governor(s).
(a) The Director shall make data, information, and samples available in accordance with the requirements and subject to the limitations of the Act, the Freedom of Information Act (5 U.S.C. 552), and the implementing regulations (43 CFR part 2).
(b) Geophysical data, processed G&G information, interpreted G&G information, and other data and information submitted pursuant to the requirements of this part shall not be available for public inspection without the consent of the lessee so long as the lease remains in effect, unless the Director determines that earlier limited release of such information is necessary for the unitization of operations on two or more leases, to ensure proper Mining Plans for a common orebody, or to promote operational safety. When the Director determines that early limited release of data and information is necessary, the data and information shall be shown only to persons with a
(c) Geophysical data, processed geophysical information and interpreted geophysical information collected on a lease with high resolution systems (including, but not limited to, bathymetry, side-scan sonar, subbottom profiler, and magnetometer) in compliance with stipulations or orders concerning protection of environmental aspects of the lease may be made available to the public 60 days after submittal to the Director, unless the lessee can demonstrate to the satisfaction of the Director that release of the information or data would unduly damage the lessee's competitive position.
(a) Proprietary data, information, and samples submitted to MMS pursuant to the requirements of this part shall be made available for inspection by representatives of adjacent State(s) upon request by the Governor(s) in accordance with paragraphs (b), (c), and (d) of this section.
(b) Disclosure shall occur only after the Governor has entered into an agreement with the Secretary providing that:
(1) The confidentiality of the information shall be maintained;
(2) In any action commenced against the Federal Government or the State for failure to protect the confidentiality of proprietary information, the Federal Government or the State, as the case may be, may not raise as a defense any claim of sovereign immunity or any claim that the employee who revealed the proprietary information, which is the basis of the suit, was acting outside the scope of the person's employment in revealing the information;
(3) The State agrees to hold the United States harmless for any violation by the State or its employees or contractors of the agreement to protect the confidentiality of proprietary data, information, and samples; and
(c) The data, information, and samples available for inspection by representatives of adjacent State(s) pursuant to an agreement shall be related to leased lands.
In the event of a controversy between the United States and a State as to whether certain lands are subject to Federal or State jurisdiction, either the Governor of the State or the Secretary may initiate negotiations in an attempt to settle the jurisdictional controversy. With the concurrence of the Attorney General, the Secretary may enter into an agreement with a State with respect to OCS mineral activities and to payment and impounding of rents, royalties, and other sums and with respect to the issuance or nonissuance of new leases pending settlement of the controversy.
Subject to the authority of the Secretary, the following activities are subject to the regulations in this part and are under the jurisdiction of the Director: Exploration, testing, and mining operations together with the associated environmental protection measures needed to permit those activities to be conducted in an environmentally responsible manner; handling, measurement, and transportation of OCS minerals; and other operations and activities conducted pursuant to a lease issued under part 281 of this chapter, or pursuant to a right of use and easement granted under this part, by or on behalf of a lessee or the holder of a right of use and easement.
(a) In the exercise of jurisdiction under § 282.10, the Director is authorized and directed to act upon the requests, applications, and notices submitted under the regulations in this part; to issue either written or oral orders to govern lease operations; and to require compliance with applicable laws, regulations, and lease terms so that all operations conform to sound conservation practices and are conducted in a manner which is consistent with the following:
(1) Make such OCS minerals available to meet the nation's needs in a timely manner;
(2) Balance OCS mineral resource development with protection of the human, marine, and coastal environments;
(3) Ensure the public a fair and equitable return on OCS minerals leased on the OCS; and
(4) Foster and encourage private enterprise.
(b)(1) The Director is to be provided ready access to all OCS mineral resource data and all environmental data acquired by the lessee or holder of a right of use and easement in the course of operations on a lease or right of use and easement and may require a lessee or holder to obtain additional environmental data when deemed necessary to assure adequate protection of the human, marine, and coastal environments.
(2) The Director is to be provided an opportunity to inspect, cut, and remove representative portions of all samples acquired by a lessee in the course of operations on the lease.
(c) In addition to the rights and privileges granted to a lessee under any lease issued or maintained under the Act, on request, the Director may grant a lessee, subject to such conditions as the Director may prescribe, a right of use and easement to construct and maintain platforms, artificial islands, and/or other installations and devices which are permanently or temporarily attached to the seabed and which are needed for the conduct of leasehold exploration, testing, development, production, and processing activities or other leasehold related operations whether on or off the lease.
(d)(1) The Director may approve the consolidation of two or more OCS mineral leases or portions of two or more OCS mineral leases into a single mining unit requested by lessees, or the Director may require such consolidation when the operation of those leases or portions of leases as a single mining unit is in the interest of conservation of the natural resources of the OCS or the prevention of waste. A mining unit may also include all or portions of one or more OCS mineral leases with all or portions of one or more adjacent State leases for minerals in a common orebody. A single unit operator shall be responsible for submission of required Delineation, Testing, and Mining Plans covering OCS mineral operations for an approved mining unit.
(2) Operations such as exploration, testing, and mining activities conducted in accordance with an approved plan on any lease or portion of a lease which is subject to an approved mining unit shall be considered operations on each of the leases that is made subject to the approved mining unit.
(3) Minimum royalty paid pursuant to a Federal lease, which is subject to an approved mining unit, is creditable against the production royalties allocated to that Federal lease during the lease year for which the minimum royalty is paid.
(4) Any OCS minerals produced from State and Federal leases which are subject to an approved mining unit shall be accounted for separately unless a method of allocating production between State and Federal leases has been approved by the Director and the appropriate State official.
(a) The Director is responsible for the regulation of activities to assure that all operations conducted under a lease or right of use and easement are conducted in a manner that protects the environment and promotes orderly development of OCS mineral resources. Those activities are to be designed to prevent serious harm or damage to, or waste of, any natural resource (including OCS mineral deposits and oil, gas, and sulphur resources in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human environment.
(b)(1) In the evaluation of a Delineation Plan, the Director shall consider whether the plan is consistent with:
(i) The provisions of the lease;
(ii) The provisions of the Act;
(iii) The provisions of the regulations prescribed under the Act;
(iv) Other applicable Federal law; and
(v) Requirements for the protection of the environment, health, and safety.
(2) Within 30 days following the completion of an environmental assessment or other NEPA document prepared pursuant to the regulations implementing NEPA or within 30 days following the comment period provided in § 282.4(b) of this part, the Director shall:
(i) Approve any Delineation Plan which is consistent with the criteria in paragraph (b)(1) of this section;
(ii) Require the lessee to modify any Delineation Plan that is inconsistent with the criteria in paragraph (b)(1) of this section; or
(iii) Disapprove a Delineation Plan when it is determined that an activity proposed in the plan would probably cause serious harm or damage to life (including fish and other aquatic life); to property; to natural resources of the OCS including mineral deposits (in areas leased or not leased); or to the marine, coastal, or human environment, and the proposed activity cannot be modified to avoid the conditions.
(3) The Director shall notify the lessee in writing of the reasons for disapproving a Delineation Plan or for requiring modification of a plan and the conditions that must be met for plan approval.
(c)(1) In the evaluation of a Testing Plan, the Director shall consider whether the plan is consistent with:
(i) The provisions of the lease;
(ii) The provisions of the Act;
(iii) The provisions of the regulations prescribed under the Act;
(iv) Other applicable Federal law;
(v) Environmental, safety, and health requirements; and
(vi) The statutory requirement to protect property, natural resources of the OCS, including mineral deposits (in areas leased or not leased), and the national security or defense.
(2) Within 60 days following the release of a final EIS prepared pursuant to NEPA or within 60 days following the comment period provided in § 282.4(c) of this part, the Director shall:
(i) Approve any Testing Plan which is consistent with the criteria in paragraph (c)(1) of this section;
(ii) Require the lessee to modify any Testing Plan which is inconsistent with the criteria in paragraph (c)(1) of this section; or
(iii) Disapprove any Testing Plan when the Director determines the existence of exceptional geological conditions in the lease area, exceptional resource values in the marine or coastal environment, or other exceptional circumstances and that (A) implementation of the activities described in the plan would probably cause serious harm and damage to life (including fish and other aquatic life), to property, to any mineral deposit (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environments; (B) that the threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and (C) the advantages of disapproving the Testing Plan outweigh the advantages of development and production of the OCS mineral resources.
(3) The Director shall notify the lessee in writing of the reason(s) for disapproving a Testing Plan or for requiring modification of a Testing Plan and the conditions that must be met for approval of the plan.
(d)(1) In the evaluation of a Mining Plan, the Director shall consider whether the plan is consistent with:
(i) The provisions of the lease;
(ii) The provisions of the Act;
(iii) The provisions of the regulations prescribed under the Act;
(iv) Other applicable Federal law;
(v) Environmental, safety, and health requirements; and
(vi) The statutory requirements to protect property, natural resources of the OCS, including mineral deposits (in areas leased or not leased), and the national security or defense.
(2) Within 60 days following the release of a final EIS prepared pursuant to NEPA or within 60 days following the comment period provided in § 282.4(d) of this part, the Director shall:
(i) Approve any Mining Plan which is consistent with the criteria in paragraph (d)(1) of this section;
(ii) Require the lessee to modify any Mining Plan which is inconsistent with the criteria in paragraph (d)(1) of this section; or
(iii) Disapprove any Mining Plan when the Director determines the existence of exceptional geological conditions in the lease area, exceptional resource values in the marine or coastal environment, or other exceptional circumstances, and that—
(A) Implementation of the activities described in the plan would probably cause serious harm and damage to life (including fish and other aquatic life), to property, to any mineral deposit (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environments;
(B) That the threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(C) The advantages of disapproving the Mining Plan outweigh the advantages of development and production of the OCS mineral resources.
(3) The Director shall notify the lessee in writing of the reason(s) for disapproving a Mining Plan or for requiring modification of a Mining Plan and the conditions that must be met for approval of the plan.
(e) The Director shall assure that a scheduled onsite compliance inspection of each facility which is subject to regulations in this part is conducted at least once a year. The inspection shall be to determine that the lessee is in compliance with the requirements of the law; provisions of the lease; the approved Delineation, Testing, or Mining Plan; and the regulations in this part. Additional unscheduled onsite inspections shall be conducted without advance notice to the lessee to assure compliance with the provisions of applicable law; the lease; the approved Delineation, Testing, or Mining Plan; and the regulations in this part.
(f)(1) The Director shall, after completion of the technical and environmental evaluations, approve, disapprove, or require modification of the lessee's requests, applications, plans, and notices submitted pursuant to the provisions of this part; issue orders to govern lease operations; and require compliance with applicable provisions of the law, the regulations, the lease, and the approved Delineation, Testing, or Mining Plans. The Director may give oral orders or approvals whenever prior approval is required before the commencement of an operation or activity. Oral orders or approvals given in response to a written request shall be confirmed in writing within 3 working days after issuance of the order or granting of the oral approval.
(2) The Director shall, after completion of the technical and environmental evaluations, approve, disapprove, or require modification, as appropriate, of the design plan, fabrication plan, and installation plan for platforms, artificial islands, and other installations and devices permanently or temporarily attached to the seabed. The approval, disapproval, or requirement to modify such plans may take the form of a condition of granting a right of use and easement under paragraph (a) of this section or as authorized under any lease issued or maintained under the Act.
(g) The Director shall establish practices and procedures to govern the collection of all rents, royalties, and other payments due the Federal Government in accordance with terms of the leasing notice, the lease, and the applicable Royalty Management regulations listed in § 281.26(i) of this chapter.
(h) The Director may prescribe or approve, in writing or orally, departures from the operating requirements of the regulations of this part when such departures are necessary to facilitate the proper development of a lease; to conserve natural resources; or to protect life (including fish and other aquatic life), property, or the marine, coastal, or human environment.
(a) The Director may direct the suspension or temporary prohibition of production or any other operation or activity on all or any part of a lease when it has been determined that such suspension or temporary prohibition is in the national interest to:
(1) Facilitate proper development of a lease including a reasonable time to develop a mine and construct necessary support facilities, or
(2) Allow for the construction or negotiation for use of transportation facilities.
(b) The Director may also direct or, at the request of the lessee, approve a suspension or temporary prohibition of production or any other operation or activity, if:
(1) The lessee failed to comply with a provision of applicable law, regulation, order, or the lease;
(2) There is a threat of serious, irreparable, or immediate harm or damage to life (including fish and other aquatic life), property, any mineral deposit, or the marine, coastal, or human environment;
(3) The suspension or temporary prohibition is in the interest of national security or defense;
(4) The suspension or temporary prohibition is necessary for the initiation and conduct of an environmental evaluation to define mitigation measures to avoid or minimize adverse environmental impacts.
(5) The suspension or temporary prohibition is necessary to facilitate the installation of equipment necessary for safety of operations and protection of the environment;
(6) The suspension or temporary prohibition is necessary to allow for undue delays encountered by the lessee in obtaining required permits or consents, including administrative or judicial challenges or appeals;
(7) The Director determines that continued operations would result in premature abandonment of a producing mine, resulting in the loss of otherwise recoverable OCS minerals;
(8) The Director determines that the lessee cannot successfully operate a producing mine due to market conditions that are either temporary in nature or require temporary shutdown and reinvestment in order for the lessee to adapt to the conditions; or
(9) The suspension or temporary prohibition is necessary to comply with judicial decrees prohibiting production or any other operation or activity, or the permitting of those activities, effective the date set by the court for that prohibition.
(c) When the Director orders or approves a suspension or a temporary prohibition of operation or activity including production on all of a lease pursuant to paragraph (a) or (b) of this section, the term of the lease shall be extended for a period of time equal to the period of time that the suspension or temporary prohibition is in effect, except that no lease shall be so extended when the suspension or temporary prohibition is the result of the lessee's gross negligence or willful violation of a provision of the lease or governing regulations.
(d) The Director may, at any time within the period prescribed for a suspension or temporary prohibition issued pursuant to paragraph (b)(2) of this section, require the lessee to submit a Delineation, Testing, or Mining Plan for approval in accordance with the requirements for the approval of such plans in this part.
(e)(1) When the Director orders or issues a suspension or a temporary prohibition pursuant to paragraph (b)(2) of this section, the Director may require the lessee to conduct site-specific studies to identify and evaluate the cause(s) of the hazard(s) generating the suspension or temporary prohibition, the potential for damage from the hazard(s), and the measures available for mitigating the hazard(s). The nature, scope, and content of any study shall be subject to approval by the Director. The lessee shall furnish copies and all results of any such study to the Director. The cost of the study shall be borne by the lessee unless the Director arranges for the cost of the study to be borne by a party other than the lessee. The Director shall make results of any such study available to interested parties and to the public as soon as practicable after the completion of the study and submission of the results thereof.
(2) When the Director determines that measures are necessary, on the basis of the results of the studies conducted in accordance with paragraph (e)(1) of this section and other information available to and identified by the Director, the lessee shall be required to take appropriate measures to mitigate, avoid, or minimize the damage or potential damage on which the suspension or temporary prohibition is based. When deemed appropriate by the Director, the lessee shall submit a revised Delineation, Testing, or Mining Plan to incorporate the mitigation measures required by the Director. In choosing
(f)(1) If under the provisions of paragraphs (b) (2), (3), and (4) of this section, the Director, with respect to any lease, directs the suspension of production or other operations on the entire leasehold, no payment of rental or minimum royalty shall be due for or during the period of the directed suspension and the time for the lessee specify royalty free period of a period of reduced royalty pursuant to § 281.28(b) of this subchapter will be extended for the period of directed suspension. If under the provisions of paragraphs (b) (2), (3), and (4) of this section the Director, with respect to a lease on which there has been no production, directs the suspension of operations on the entire leasehold, no payment of rental shall be due during the period of the directed suspension.
(2) If under the provisions of this section, the Director grants the request of a lessee for a suspension of production or other operations, the lessee's obligations to pay rental, minimum royalty, or royalty shall continue to apply during the period of the approved suspension, unless the Director's approval of the lessee's request for suspension authorizes the payment of a lesser amount during the period of approved suspension. If under the provision of this section, the Director grants a lessee's request for a suspension of production or other operations for a lease which includes provisions for a time period which the lessee may specify during which production from the leasehold would be royalty free or subject to a reduced royalty obligation pursuant to § 281.28(b) of this subchapter, the time during which production from a leasehold may be royalty free or subject to a reduced royalty obligation shall not be extended unless the Director's approval of the suspension specifies otherwise.
(3) If the lease anniversary date falls within a period of suspension for which no rental or minimum royalty payments are required under paragraph (a) of this section, the prorated rentals or minimum royalties are due and payable as of the date the suspension period terminates. These amounts shall be computed and notice thereof given the lessee. The lessee shall pay the amount due within 30 days after receipt of such notice. The anniversary date of a lease shall not change by reason of any period of lease suspension or rental or royalty relief resulting therefrom.
(a)(1) If the Director determines that a lessee has failed to comply with applicable provisions of law; the regulations in this part; other applicable regulations; the lease; the approved Delineation, Testing, or Mining Plan; or the Director's orders or instructions, and the Director determines that such noncompliance poses a threat of immediate, serious, or irreparable damage to the environment, the mine or the deposit being mined, or other valuable mineral deposits or other resources, the Director shall order the lessee to take immediate and appropriate remedial action to alleviate the threat. Any oral orders shall be followed up by service of a notice of noncompliance upon the lessee by delivery in person to the lessee or agent, or by certified or registered mail addressed to the lessee at the last known address.
(2) If the Director determines that the lessee has failed to comply with applicable provisions of law; the regulations in this part; other applicable regulations; the lease; the requirements of an approved Delineation, Testing, or Mining Plan; or the Director's orders or instructions, and such noncompliance does not pose a threat of immediate, serious, or irreparable damage to the environment, the mine or the deposit being mined, or other valuable mineral deposits or other resources, the Director shall serve a notice of noncompliance upon the lessee by delivery in person to the lessee or agent
(b) A notice of noncompliance shall specify in what respect(s) the lessee has failed to comply with the provisions of applicable law; regulations; the lease; the requirements of an approved Delineation, Testing, or Mining Plan; or the Director's orders or instructions, and shall specify the action(s) which must be taken to correct the noncompliance and the time limits within which such action must be taken.
(c) Failure of a lessee to take the actions specified in the notice of noncompliance within the time limit specified shall be grounds for a suspension of operations and other appropriate actions, including but not limited to the assessment of a civil penalty of up to $10,000 per day for each violation that is not corrected within the time period specified (43 U.S.C. 1350(b)).
(d) Whenever the Director determines that a violation of or failure to comply with any provision of the Act; or any provision of a lease, license, or permit issued pursuant to the Act; or any provision of any regulation promulgated under the Act probably occurred and that such apparent violation continued beyond notice of the violation and the expiration of the reasonable time period allowed for corrective action, the Director shall follow the procedures concerning remedies and penalties in subpart N, Remedies and Penalties, of part 250 of this title to determine and assess an appropriate penalty.
(e) The remedies and penalties prescribed in this section shall be concurrent and cumulative, and the exercise of one shall not preclude the exercise of the other. Further, the remedies and penalties prescribed in this section shall be in addition to any other remedies and penalties afforded by any other law or regulation (43 U.S.C. 1350(e)).
(a) Whenever the owner of a nonproducing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, and the default continues for a period of 30 days after mailing of notice by registered or certified letter to the lease owner at the owner's record post office address, the Secretary may cancel the lease pursuant to section 5(c) of the Act, and the lessee shall not be entitled to compensation. Any such cancellation is subject to judicial review as provided by section 23(b) of the Act.
(b) Whenever the owner of any producing lease fails to comply with any of the provisions of the Act, the lease, or the regulations issued under the Act, the Secretary may cancel the lease only after judicial proceedings pursuant to section 5(d) of the Act, and the lessee shall not be entitled to compensation.
(c) Any lease issued under the Act, whether producing or not, may be canceled by the Secretary upon proof that it was obtained by fraud or misrepresentation and after notice and opportunity to be heard has been afforded to the lessee.
(d) The Secretary may cancel a lease in accordance with the following:
(1) Cancellation may occur at any time if the Secretary determines after a hearing that—
(i) Continued activity pursuant to such lease would probably cause serious harm or damage to life (including fish and other aquatic life), to property, to any mineral (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environment;
(ii) The threat of harm or damage will not disappear or decrease to an acceptable extent within a reasonable period of time; and
(iii) The advantages of cancellation outweigh the advantages of continuing such lease in force.
(2) Cancellation shall not occur unless and until operations under such lease shall have been under suspension or temporary prohibition by the Secretary, with due extension of any lease term continuously for a period of 5 years or for a lesser period upon request of the lessee;
(3) Cancellation shall entitle the lessee to receive such compensation as is shown to the Secretary as being equal to the lesser of—
(i) The fair value of the canceled rights as of the date of cancellation,
(ii) The excess, if any, over the lessee's revenue from the lease (plus interest thereon from the date of receipt to date of reimbursement) of all consideration paid for the lease and all direct expenditures made by the lessee after the date of issuance of such lease and in connection with exploration or development, or both, pursuant to the lease (plus interest on such consideration and such expenditures from date of payment to date of reimbursement), except that in the case of joint leases which are canceled due to the failure of one or more partners to exercise due diligence, the innocent parties shall have the right to seek damages for such loss from the responsible party or parties and the right to acquire the interests of the negligent party or parties and be issued the lease in question.
(iii) The lessee shall not be entitled to compensation where one of the following circumstances exists when a lease is canceled:
(A) A producing lease is forfeited or is canceled pursuant to section (5)(d) of the Act;
(B) A Testing Plan or Mining Plan is disapproved because the lessee's failure to demonstrate compliance with the requirements of applicable Federal law; or
(C) The lessee of a nonproducing lease fails to comply with a provision of the Act, the lease, or regulations issued under the Act, and the noncompliance continues for a period of 30 days or more after the mailing of a notice of noncompliance by registered or certified letter to the lessee.
(a) The lessee shall comply with the provisions of applicable laws; regulations; the lease; the requirements of the approved Delineation, Testing, or Mining Plans; and other written or oral orders or instructions issued by the Director when performing exploration, testing, development, and production activities pursuant to a lease issued under part 281 of this title. The lessee shall take all necessary precautions to prevent waste and damage to oil, gas, sulphur, and other OCS mineral-bearing formations and shall conduct operations in such manner that does not cause or threaten to cause harm or damage to life (including fish and other aquatic life); to property; to the national security or defense; or to the marine, coastal, or human environment (including onshore air quality). The lessee shall make all mineral resource data and information and all environmental data and information acquired by the lessee in the course of exploration, testing, development, and production operations on the lease available to the Director for examination and copying at the lease site or an onshore location convenient to the Director.
(b) In all cases where there is more than one lease owner of record, one person shall be designated payor for the lease. The payor shall be responsible for making all rental, minimum royalty, and royalty payments.
(c) In all cases where lease operations are not conducted by the sole lessee, a “designation of operator” shall be submitted to and accepted by the Director prior to the commencement of leasehold operations. This designation when accepted will be recognized as authority for the designee to act on behalf of the lessees and to fulfill the lessees’ obligations under the Act, the lease, and the regulations of this part. All changes of address and any termination of a designation of operator shall be reported immediately, in writing, to the Director. In the case of a termination of a designation of operator or in the event of a controversy between the lessee and the designated operator, both the lessee and the designated operator will be responsible for the protection of the interests of the lessor.
(d) When required by the Director or at the option of the lessee, the lessee
(e) Before beginning operations, the lessee shall inform the Director in writing of any designation of a local representative under paragraph (d) of this section and the address of the mine office responsible for the exploration, testing, development, or production activities; the lessee's temporary and permanent addresses; or the name and address of the designated operator who will be responsible for the operations, and who will act as the local representative of the lessee. The Director shall also be informed of each change thereafter in the address of the mine office or in the name or address of the local representative.
(f) The holder of a right of use and easement shall exercise its rights under the right of use and easement in accordance with the regulations of this part.
(g) A lessee shall submit reports and maintain records in accordance with § 282.29 of this part.
(h) When an oral approval is given by MMS in response to an oral request under these regulations, the oral request shall be confirmed in writing by the lessee or holder of a right of use and easement within 72 hours.
(i) The lessee is responsible for obtaining all permits and approvals from MMS or other Agencies needed to carry out exploration, testing, development, and production activities under a lease issued under part 281 of this title.
(a) No exploration, testing, development, or production activities, except preliminary activities, shall be commenced or conducted on any lease except in accordance with a plan submitted by the lessee and approved by the Director. Plans will not be approved before completion of comprehensive technical and environmental evaluations to assure that the activities described will be carried out in a safe and environmentally responsible manner. Prior to the approval of a plan, the Director will assure that the lessee is prepared to take adequate measures to prevent waste; conserve natural resources of the OCS; and protect the environment, human life, and correlative rights. The lessee shall demonstrate to the satisfaction of the Director that the lease is in good standing, the lessee is authorized and capable of conducting the activities described in the plan, and that an acceptable bond has been provided.
(b) Plans shall be submitted to the Director for approval. The lessee shall submit the number of copies prescribed by the Director. Such plans shall describe in detail the activities that are to be conducted and shall demonstrate that the proposed exploration, testing, development, and production activities will be conducted in an operationally safe and environmentally responsible manner that is consistent with the provisions of the lease, applicable laws, and regulations. The Governor of an affected State and other Federal Agencies shall be provided an opportunity to review and provide comments on proposed Delineation, Testing, and Mining Plans and any proposal for a significant modification to an approved plan. Following review, including the technical and environmental evaluations, the Director shall either approve, disapprove, or require the lessee to modify its proposed plan.
(c) Lessees are not required to submit a Delineation or Testing Plan prior to submittal of a proposed Testing or Mining Plan if the lessee has sufficient data and information on which to base a Testing or Mining Plan without carrying out postlease exploration and/or testing activities. A Mining Plan may include proposed exploration or testing activities where those activities are needed to obtain additional data and information on which to base plans for future mining activities. A Testing Plan may include exploration activities when those activities are needed to obtain additional data or information on which to base plans for future testing or mining activities.
(d) Preliminary activities are bathymetric, geological, geophysical, mapping, and other surveys necessary to
(e) Leasehold activities shall be carried out with due regard to conservation of resources, paying particular attention to the wise management of OCS mineral resources, minimizing waste of the leased resource(s) in mining and processing, and preventing damage to unmined parts of the mineral deposit and other resources of the OCS.
All exploration activities shall be conducted in accordance with a Delineation Plan submitted by the lessee and approved by the Director. The Delineation Plan shall describe the proposed activities necessary to locate leased OCS minerals, characterize the quantity and quality of the minerals, and generate other information needed for the development of a comprehensive Testing or Mining Plan. A Delineation Plan at a minimum shall include the following:
(a) The OCS mineral(s) or primary interest.
(b) A brief narrative description of the activities to be conducted and how the activities will lead to the discovery and evaluation of a commercially minable deposit on the lease.
(c) The name, registration, and type of equipment to be used, including vessel types as well as their navigation and mobile communication systems, and transportation corridors to be used between the lease and shore.
(d) Information showing that the equipment to be used (including the vessel) is capable of performing the intended operation in the environment which will be encountered.
(e) Maps showing the proposed locations of test drill holes, the anticipated depth of penetration of test drill holes, the locations where surficial sample were taken, and the location of proposed geophysical survey lines for each surveying method being employed.
(f) A description of measures to be taken to avoid, minimize, or otherwise mitigate air, land, and water pollution and damage to aquatic and wildlife species and their habitats; any unique or special features in the lease area; aquifers; other natural resources of the OCS; and hazards to public health, safety, and navigation.
(g) A schedule indicating the starting and completion dates for each proposed exploration activity.
(h) A list of any known archaeological resources on the lease and measures to assure that the proposed exploration activities do not damage those resources.
(i) A description of any potential conflicts with other uses and users of the area.
(j) A description of measures to be taken to monitor the effects of the proposed exploration activities on the environment in accordance with § 282.28(c) of this part.
(k) A detailed description of practices and procedures to effect the abandonment of exploration activities, e.g., plugging of test drill holes. The proposed procedures shall indicate the steps to be taken to assure that test drill holes and other testing procedures which penetrate the seafloor to a significant depth are properly sealed and that the seafloor is left free of obstructions or structures that may present a hazard to other uses or users of the OCS such as navigation or commercial fishing.
(l) A detailed description of the cycle of all materials, the method for discharge and disposal of waste and refuse, and the chemical and physical characteristics of waste and refuse.
(m) A description of the potential environmental impacts of the proposed exploration activities including the following:
(1) The location of associated port, transport, processing, and waste disposal facilities and affected environment (e.g., maps, land use, and layout);
(2) A description of the nature and degree of environmental impacts and the domestic socioeconomic effects of
(3) Any proposed mitigation measures to avoid or minimize adverse impacts on the environment;
(4) A certificate of consistency with the federally approved State coastal zone management program, where applicable; and
(5) Alternative sites and technologies considered by the lessee and the reasons why they were not chosen.
(n) Any other information needed for technical evaluation of the planned activity, such as sample analyses to be conducted at sea, and the evaluation of potential environmental impacts.
All testing activities shall be conducted in accordance with a Testing Plan submitted by the lessee and approved by the Director. Where a lessee needs more information to develop a detailed Mining Plan than is obtainable under an approved Delineation Plan, to prepare feasibility studies, to carry out a pilot program to evaluate processing techniques or technology or mining equipment, or to determine environmental effects by a pilot test mining operation, the lessee shall submit a comprehensive Testing Plan for the Director's approval. Any OCS minerals acquired during activities conducted under an approved Testing Plan will be subject to the payment of royalty pursuant to the governing lease terms. A Testing Plan at a minimum shall include the following:
(a) The nature and purpose of the proposed testing program.
(b) A comprehensive description of the activities to be performed including descriptions of the proposed methods for analysis of samples taken.
(c) A narrative description and maps showing water depths and the locations of the proposed pilot mining or other testing activities.
(d) A comprehensive description of the method and manner in which testing activities will be conducted and the results the lessee expects to obtain as a result of those activities.
(e) The name, registration, and type of equipment to be used, including vessel types together with their navigation and mobile communication systems, and transportation corridors to be used between the lease and shore.
(f) Information showing that the equipment to be used (including the vessel) is capable of performing the intended operation in the environment which will be encountered.
(g) A schedule specifying the starting and completion dates for each of the testing activities.
(h) A list of known archaeological resources on the lease and measures to be used to assure that the proposed testing activities do not damage those resources.
(i) A description of any potential conflicts with other uses and users of the area.
(j) A description of measures to be taken to avoid, minimize, or otherwise mitigate air, land, and water pollution and damage to aquatic and wildlife species and their habitat; any unique or special features in the lease area, other natural resources of the OCS; and hazards to public health, safety, and navigation.
(k) A description of the measures to be taken to monitor the impacts of the proposed testing activities in accordance with § 282.28(c) of this part.
(l) A detailed description of the cycle of all materials including samples and wastes, the method for discharge and disposal of waste and refuse, and the chemical and physical characteristics of such waste and refuse.
(m) A detailed description of practices and procedures to effect the abandonment of testing activities, e.g., abandonment of a pilot mining facility. The proposed procedures shall indicate the steps to be taken to assure that mined areas do not pose a threat to the environment and that the seafloor is left free of obstructions and structures that may present a hazard to other uses or users of the OCS such as navigation or commercial fishing.
(n) A description of potential environmental impacts of testing activities including the following:
(1) The location of associated port, transport, processing, and waste disposal facilities and affected environment (e.g., maps, land use, and layout);
(2) A description of the nature and degree of potential environmental impacts of the proposed testing activities and the domestic socioeconomic effects of construction and operation of the proposed testing facilities, including waste characteristics and toxicity;
(3) Any proposed mitigation measures to avoid or minimize adverse impacts on the environment;
(4) A certificate of consistency with the federally approved State coastal zone management program, where applicable; and
(5) Alternate sites and technologies considered by the lessee and the reasons why they were not selected.
(o) Any other information needed for technical evaluation of the planned activities and for evaluation of the impact of those activities on the human, marine, and coastal environments.
All OCS mineral development and production activities shall be conducted in accordance with a Mining Plan submitted by the lessee and approved by the Director. A Mining Plan shall include comprehensive detailed descriptions, illustrations, and explanations of the proposed OCS mineral development, production, and processing activities and accurately present the lessee's proposed plan of operation. A Mining Plan at a minimum shall include the following:
(a) A narrative description of the mining activities including:
(1) The OCS mineral(s) or material(s) to be recovered;
(2) Estimates of the number of tons and grade(s) of ore to be recovered;
(3) Anticipated annual production;
(4) Volume of ocean bottom expected to be disturbed (area and depth of disruption) each year; and
(5) All activities of the mining cycle from extraction through processing and waste disposal.
(b) Maps of the lease showing water depths, the outline of the mineral deposit(s) to be mined with cross sections showing thickness, and the area(s) anticipated to be mined each year.
(c) The name, registration, and type of equipment to be used, including vessel types as well as their navigation and mobile communication systems, and transportation corridors to be used between the lease and shore.
(d) Information showing that the equipment to be used (including the vessel) is capable of performing the intended operation in the environment which will be encountered.
(e) A description of equipment to be used in mining, processing, and transporting of the ore.
(f) A schedule indicating the anticipated starting and completion dates for each activity described in the plan.
(g) For onshore processing, a description of how OCS minerals are to be processed and how the produced OCS minerals will be weighed, assayed, and royalty determinations made.
(h) For at-sea processing, additional information including type and size of installation or structures and the method of tailings disposal.
(i) A list of known archaeological resources on the lease and the measures to be taken to assure that the proposed mining activities do not damage those resources.
(j) Description of any potential conflicts with other uses and users of the area.
(k) A detailed description of the nature and occurrence of the OCS mineral deposit(s) in the leased area with adequate maps and sections.
(l) A detailed description of development and mining methods to be used, the proposed sequence of mining or development, the expected production rate, the method and location of the proposed processing operation, and the method of measuring production.
(m) A detailed description of the method of transporting the produced OCS minerals from the lease to shore and adequate maps showing the locations of pipelines, conveyors, and other transportation facilities and corridors.
(n) A detailed description of the cycle of all materials including samples and wastes, the method of discharge and disposal of waste and refuse, and the chemical and physical characteristics of the waste and refuse.
(o) A description of measures to be taken to avoid, minimize, or otherwise mitigate air, land, and water pollution and damage to aquatic and wildlife species and their habitats; any unique or special features in the lease area,
(p) A detailed description of measures to be taken to monitor the impacts of the proposed mining and processing activities on the environment in accordance with § 282.28(c) of this part.
(q) A detailed description of practices and procedures to effect the abandonment of mining and processing activities. The proposed procedures shall indicate the steps to be taken to assure that mined areas on tailing deposits do not pose a threat to the environment and that the seafloor is left free of obstructions and structures that present a hazard to other users or uses of the OCS such as navigation or commercial fishing.
(r) A description of potential environmental impacts of mining activities including the following:
(1) The location of associated port, transport, processing, and waste disposal facilities and the affected environment (e.g., maps, land use, and layout);
(2) A description of the nature and degree of potential environmental impacts of the proposed mining activities and the domestic socioeconomic effects of construction and operation of the associated facilities, including waste characteristics and toxicity;
(3) Any proposed mitigation measures to avoid or minimize adverse impacts on the environment;
(4) A certificate of consistency with the federally approved State coastal zone management program, where applicable; and
(5) Alternative sites and technologies considered by the lessee and the reasons why they were not chosen.
(s) Any other information needed for technical evaluation of the proposed activities and for the evaluation of potential impacts on the environment.
Approved Delineation, Testing, and Mining Plans may be modified upon the Director's approval of the changes proposed. When circumstances warrant, the Director may direct the lessee to modify an approved plan to adjust to changed conditions. If the lessee requests the change, the lessee shall submit a detailed, written statement of the proposed modifications, potential, impacts, and the justification for the proposed changes. Revision of an approved plan whether initiated by the lessee or ordered by the Director shall be submitted to the Director for approval. When the Director determines that a proposed revision could result in significant change in the impacts previously identified and evaluated or requires additional permits, the proposed plan revision shall be subject to the applicable review and approval procedures of §§ 282.21, 282.22, 282.23, and 282.24 of this part.
(a) When required by the Director, a lessee shall include a Contingency Plan as part of its request for approval of a Delineation, Testing, or Mining Plan. The Contingency Plan shall comply with the requirements of § 282.28(e) of this part.
(b) The Director may order or the lessee may request the Director's approval of a modification of the Contingency Plan when such a change is necessary to reflect any new information concerning the nature, magnitude, and significance of potential equipment or procedural failures or the effectiveness of the corrective actions described in the Contingency Plan.
(a) The lessee shall conduct all exploration, testing, development, and production activities and other operations in a safe and workmanlike manner and shall maintain equipment in a manner which assures the protection of the lease and its improvements, the health and safety of all persons, and the conservation of property, and the environment.
(b) Nothing in this part shall preclude the use of new or alternative technologies, techniques, procedures, equipment, or activities, other than those prescribed in the regulations of this part, if such other technologies, techniques, procedures, equipment, or activities afford a degree of protection, safety, and performance equal to or better than that intended to be achieved by the regulations of this part, provided the lessee obtains the
(c) The lessee shall immediately notify the Director when there is a death or serious injury; fire, explosion, or other hazardous event which threatens damage to life, a mineral deposit, or equipment; spills of oil, chemical reagents, or other liquid pollutants which could cause pollution; or damage to aquatic life or the environment associated with operations on the lease. As soon as practical, the lessee shall file a detailed report on the event and action(s) taken to control the situation and to mitigate any further damage.
(d)(1) Lessees shall provide means, at all reasonable hours either day or night, for the Director to inspect or investigate the conditions of the operation and to determine whether applicable regulations; terms and conditions of the lease; and the requirements of the approved Delineation, Testing, or Mining Plan are being met.
(2) A lessee shall, on request by the Director, furnish food, quarters, and transportation for MMS representatives to inspect its facilities. Upon request, the lessee will be reimbursed by the United States for the actual costs which it incurs as a result of its providing food, quarters, and transportation for an MMS representative's stay of more than 10 hours. Request for reimbursement must be submitted within 60 days following the cost being incurred.
(e) Mining and processing vessels, platforms, structures, artificial islands, and mobile drilling units which have helicopter landing facilities shall be identified with at least one sign using letters and figures not less than 12 inches in height. Signs for structures without helicopter landing facilities shall be identified with at least one sign using letters and figures not less than 3 inches in height. Signs shall be affixed at a location that is visible to approaching traffic and shall contain the following information which may be abbreviated:
(1) Name of the lease operator;
(2) The area designation based on Official OCS Protraction Diagrams;
(3) The block number in which the facility is located; and
(4) Vessel, platform, structure, or rig name.
(f)(1) Drilling.
(i) When drilling on lands valuable or potentially valuable for oil and gas or geopressured or geothermal resources, drilling equipment shall be equipped with blowout prevention and control devices acceptable to the Director before penetrating more than 500 feet unless a different depth is specified in advance by the Director.
(ii) In cases where the Director determines that there is sufficient liklihood of encountering pressurized hydrocarbons, the Director may require that the lessee comply with all or portions of the requirements in part 250, subpart D, of this title.
(iii) Before drilling any hole which may penetrate an aquifer, the lessee shall follow the procedures included in the approved plan for the penetration and isolation of the aquifer during the drilling operation, during use of the hole, and for subsequent abandonment of the hole.
(iv) Cuttings from holes drilled on the lease shall be disposed of and monitored in accordance with the approved plan.
(v) The use of muds in drilling holes on the lease and their subsequent disposition shall be according to the approved plan.
(2) All drill holes which are susceptible to logging shall be logged, and the lessee shall prepare a detailed lithologic log of each drill hole. Drill holes which are drilled deeper than 500 feet shall be drilled in a manner which permits logging. Copies of logs of cores and cuttings and all in-hole surveys such as electronic logs, gamma ray logs, neutron density logs, and sonic logs shall be provided to the Director.
(3) Drill holes for exploration, testing, development, or production shall be properly plugged and abandoned to the satisfaction of the Director in accordance with the approved plan and in such a manner as to protect the surface and not endanger any operation; any freshwater aquifer; or deposit of oil, gas, or other mineral substance.
(g) The use of explosives on the lease shall be in accordance with the approved plan.
(h)(1) Any equipment placed on the seabed shall be designed to allow its recovery and removal upon abandonment of leasehold activities.
(2) Disposal of equipment, cables, chains, containers, or other materials into the ocean is prohibited.
(3) Materials, equipment, tools, containers, and other items used on the OCS which are of such shape or configuration that they are likely to snag or damage fishing devices shall be handled and marked as follows:
(i) All loose materials, small tools, and other small objects shall be kept in a suitable storage area or a marked container when not in use or in a marked container before transport over OCS waters;
(ii) All cable, chain, or wire segments shall be recovered after use and securely stored;
(iii) Skid-mounted equipment, portable containers, spools or reels, and drums shall be marked with the owner's name prior to use or transport over OCS waters; and
(iv) All markings must clearly identify the owner and must be durable enough to resist the effects of the environmental conditions to which they are exposed.
(4) Any equipment or material described in paragraphs (h)(2), (h)(3)(ii), and (h)(3)(iii) of this section that is lost overboard shall be recorded on the daily operations report of the facility and reported to the Director and to the U.S. Coast Guard.
(i) Any bulk sampling or testing that is necessary to be conducted prior to submission of a Mining Plan shall be in accordance with an approved Testing Plan. The sale of any OCS minerals acquired under an approved Testing Plan shall be subject to the payment of the royalty specified in the lease to the United States.
(j) Installations and structures.
(1) The lessee shall design, fabricate, install, use, inspect, and maintain all installations and structures, including platforms on the OCS, to assure the structural integrity of all installations and structures for the safe conduct of exploration, testing, mining, and processing activities considering the specific environmental conditions at the location of the installation or structure.
(2) All fixed or bottom-founded platforms or other structures, e.g., artificial islands shall be designed, fabricated, installed, inspected, and maintained in accordance with the provisions of part 250, subpart I, of this title.
(k) The lessee shall not produce any OCS mineral until the method of measurement and the procedures for product valuation have been instituted in accordance with the approved Testing or Mining Plan. The lessee shall enter the weight or quantity and quality of each mineral produced in accordance with § 282.29 of this title.
(l) The lessee shall conduct OCS mineral processing operations in accordance with the approved Testing or Mining Plan and use due diligence in the reduction, concentration, or separation of mineral substances by mechanical or chemical processes, by evaporation, or other means, so that the percentage of concentrates or other mineral substances are recovered in accordance with the practices approved in the Testing or Mining Plan.
(m) No material shall be discharged or disposed of except in accordance with the approved disposal practice and procedures contained in the approved Delineation, Testing, or Mining Plan.
(a) Exploration, testing, development, production, and processing activities proposed to be conducted under a lease will only be approved by the Director upon the determination that the adverse impacts of the proposed activities can be avoided, minimized, or otherwise mitigated. The Director shall take into account the information contained in the sale-specific environmental evaluation prepared in association with the lease offering as well as the site- and operational-specific environmental evaluations prepared in association with the review and evaluation of the approved Delineation, Testing, or Mining Plan. The Director's review of the air quality consequences of proposed OCS activities will follow the practices and procedures specified in
(b) If the baseline data available are judged by the Director to be inadequate to support an environmental evaluation of a proposed Delineation, Testing, or Mining Plan, the Director may require the lessee to collect additional environmental baseline data prior to the approval of the activities proposed.
(c)(1) The lessee shall monitor activities in a manner that develops the data and information necessary to enable the Director to assess the impacts of exploration, testing, mining, and processing activities on the environment on and off the lease; develop and evaluate methods for mitigating adverse environmental effects; validate assessments made in previous environmental evaluations; and ensure compliance with lease and other requirements for the protection of the environment.
(2) Monitoring of environmental effects shall include determination of the spatial and temporal environmental changes induced by the exploration, testing, development, production, and processing activities on the flora and fauna of the sea surface, the water column, and/or the seafloor.
(3) The Director may place observers onboard exploration, testing, mining, and processing vessels; installations; or structures to ensure that the provisions of the lease, the approved plan, and these regulations are followed and to evaluate the effectiveness of the approved monitoring and mitigation practices and procedures in protecting the environment.
(4) The Director may order or the lessee may request a modification of the approved monitoring program prior to the startup of testing activities or commercial-scale recovery, and at other appropriate times as necessary, to reflect accurately the proposed operations or to incorporate the results of recent research or improved monitoring techniques.
(5) When prototype test mining is proposed, the lessee shall include a monitoring strategy for assessing the impacts of the testing activities and for developing a strategy for monitoring commercial-scale recovery and mitigating the impacts of commercial-scale recovery more effectively. At a minimum, the proposed monitoring activities shall address specific concerns expressed in the lease-sale environmental analysis.
(6) When required, the monitoring plan shall specify:
(i) The sampling techniques and procedures to be used to acquire the needed data and information;
(ii) The format to be used in analysis and presentation of the data and information;
(iii) The equipment, techniques, and procedures to be used in carrying out the monitoring program; and
(iv) The name and qualifications of person(s) designated to be responsible for carrying out the environmental monitoring.
(d) Lessees shall develop and conduct their operations in a manner designed to avoid, minimize, or otherwise mitigate environmental impacts and to demonstrate the effectiveness of efforts to that end. Based upon results of the monitoring program, the Director may specify particular procedures for mitigating environmental impacts.
(e) In the event that equipment or procedural failure might result in significant additional damage to the environment, the lessee shall submit a Contingency Plan which specifies the procedures to be followed to institute corrective actions in response to such a failure and to minimize adverse impacts on the environment. Such procedures shall be designed for the site and mining activities described in the approved Delineation, Testing, or Mining Plan.
(a) A report of the amount and value of each OCS mineral produced from each lease shall be made by the payor for the lease for each calendar month, beginning with the month in which approved testing, development, or production activities are initiated and shall be filed in duplicate with the Director on or before the 20th day of the succeeding month, unless an extension of time for the filing of such report is granted by the Director. The report shall disclose accurately and in detail
(b) The lessee shall submit a status report on exploration and/or testing activities under an approved Delineation or Testing Plan to the Director within 30 days of the close of each calendar quarter which shall include:
(1) A summary of activities conducted;
(2) A listing of all geophysical and geochemical data acquired and developed such as acoustic or seismic profiling records;
(3) A map showing location of holes drilled and where bottom samples were taken; and
(4) Identification of samples analyzed.
(c) Each lessee shall submit to the Director a report of exploration and/or testing activities within 3 months after the completion of operations. The final report of exploration and/or testing activities conducted on the lease shall include:
(1) A description of work performed;
(2) Charts, maps, or plats depicting the area and leases in which activities were conducted specifically identifying the lines of geophysical traverses and/or the locations where geological activity was conducted and/or the locations of other exploration and testing activities;
(3) The dates on which the actual operations were performed;
(4) A narrative summary of any mineral occurrences; environmental hazards; and effects of the activities on the environment, aquatic life, archaeological resources, or other uses and users of the area in which the activities were conducted;
(5) Such other descriptions of the activities conducted as may be specified by the Director; and
(6) Records of all samples from core drilling or other tests made on the lease. The records shall be in such form that the location and direction of the samples can be accurately located on a map. The records shall include logs of all strata penetrated and conditions encountered, such as minerals, water, gas, or unusual conditions, and copies of analyses of all samples analyzed.
(d) The lessee shall report the results of environmental monitoring activities required in § 282.28 of this part and shall submit such other environmental data as the Director may require to conform with the requirements of these regulations.
(e)(1) All maps shall be appropriately marked with reference to official lease boundaries and elevations marked with reference to sea level. When required by the Director, vertical projections and cross sections shall accompany plan views. The maps shall be kept current and submitted to the Director annually, or more often when required by the Director. The accuracy of maps furnished shall be certified by a professional engineer or land surveyor.
(2) The lessee shall prepare such maps of the leased lands as are necessary to show the geological conditions as determined from G&G surveys, bottom sampling, drill holes, trenching, dredging, or mining. All excavations shall be shown in such manner that the volume of OCS minerals produced during a royalty period can be accurately ascertained.
(f) Any lessee who acquires rock, mineral, and core samples under a lease shall keep a representative split of each geological sample and a quarter longitudinal segment of each core for 5 years during which time the samples shall be available for inspection at the convenience of the Director who may take cuts of such cores, cuttings, and samples.
(g)(1) The lessee shall keep all original data and information available for inspection or duplication, by the Director at the expense of the lessor, as long
(2) Navigation tapes showing the location(s) where samples were taken and test drilling conducted shall be retained for as long as the lease continues in force.
(h) Lessees shall maintain records in which will be kept an accurate account of all ore and rock mined; all ore put through a mill; all mineral products produced; all ore and mineral products sold, transferred, used, or otherwise disposed of and to whom sold or transferred, and the inventory weight, assay value, moisture content, base sales price, dates, penalties, and price received. The percentage of each of the mineral products recovered and the percentages lost shall be shown. The records associated with activities on a lease shall be available to the Director for auditing.
(i) When special forms or reports other than those referred to in the regulations in this part may be necessary, instructions for the filing of such forms or reports will be given by the Director.
(a) A right of use and easement that includes any area subject to a lease issued or maintained under the Act shall be granted only after the lessee has been notified by the requestor and afforded the opportunity to comment on the request. A holder of a right under a right of use and easement shall exercise that right in accordance with the requirements of the regulations in this part. A right of use and easement shall be exercised only in a manner which does not interfere unreasonably with operations of any lessee on its lease.
(b) Once a right of use and easement has been exercised, the right shall continue, beyond the termination of any lease on which it may be situated, as long as it is demonstrated to the Director that the right of use and easement is being exercised by the holder of the right and that the right of use and easement continues to serve the purpose specified in the grant. If the right of use and easement extends beyond the termination of any lease on which the right may be situated or if it is situated on an unleased portion of the OCS, the rights of all subsequent lessees shall be subject to such right. Upon termination of a right of use and easement, the holder of the right shall abandon the premises in the same manner that a lessee abandons activities on a lease to the satisfaction of the Director.
A lessee may submit a request for a suspension of production or other operations. The request shall include justification for granting the requested suspension, a schedule of work leading to the initiation or restoration of production or other operations, and any other information the Director may require.
(a) Pursuant to the requirements for a bond in § 281.33 of this title, prior to the commencement of any activity on a lease, the lessee shall submit a surety or personal bond to cover the lessee's royalty and other obligations under the lease as specified in this section.
(b) All bonds furnished by a lessee or operator must be in a form approved by the Associate Director for Offshore Minerals Management. A single copy of the required form is to be executed by the principal or, in the case of surety bonds, by both the principal and an acceptable surety.
(c) Only those surety bonds issued by qualified surety companies approved by the Department of the Treasury shall be accepted. (See Department of Treasury Circular No. 570 and any supplemental or replacement circulars.)
(d) Personal bonds shall be accompanied by a cashier's check, certified check, or negotiable U.S. Treasury bonds of an equal value to the amount specified in the bond. Negotiable Treasury bonds shall be accompanied by a proper conveyance of full authority to the Director to sell such securities in
(e) A bond in the minimum amount of $50,000 to cover the lessee's obligations under the lease shall be submitted prior to the commencement of any activity on a leasehold. A $50,000 bond shall not be required on a lease if the lessee already maintains or furnishes a $300,000 bond conditioned on compliance with the terms of leases for OCS minerals other than oil, gas, and sulphur held by the lessee on the OCS for the area in which the lease is located. A bond submitted pursuant to § 256.58(a) of this chapter may be amended to include the aforementioned condition for compliance. Prior to approval of a Delineation, Testing, or Mining Plan, the bond amount shall be adjusted, if appropriate, to cover the operations and activities described in the proposed plan.
(f) For the purposes of this section there are four areas:
(1) The Gulf of Mexico;
(2) The area offshore the Pacific Coast States of California, Oregon,Washington, and Hawaii;
(3) The area offshore the coast of Alaska; and
(4) The area offshore the Atlantic coast.
(g) A separate bond shall be required for each area. An operator's bond may be submitted for a specific lease(s) in the same amount as the lessee's bond(s) applicable to the lease(s) involved.
(h) Where, upon a default, the surety makes a payment to the United States of an obligation incurred under a lease, the face amount of the surety bond and the surety's liability thereunder shall be reduced by the amount of such payment.
(i) After default, the principal shall, within 6 months after notice or within such shorter period as may be fixed by the Director, either post a new bond or increase the existing bond to the amount previously held. In lieu thereof, the principal may, within that time, file separate or substitute bonds for each lease. Failure to meet these requirements may result in a suspension of operations including production on leases covered by such bonds.
(j) The Director shall not consent to termination of the period of liability of any bond unless an acceptable alternative bond has been filed or until all the terms and conditions of the lease covered by the bond have been met.
In the event that the provisions of royalty management regulations do not apply to the specific commodities produced under regulations in this part, the lessee shall comply with procedures specified in the leasing notice.
Rentals, royalties, and other payments due the Federal Government on leases for OCS minerals shall be paid and reports submitted by the payor for a lease in accordance with § 281.26 of this title.
See 30 CFR part 290 for instructions on how to appeal any order or decision that we issue under this part.
5 U.S.C. 301
The purpose of this subpart is to explain the procedures for appeals of Minerals Management Service (MMS) Offshore Minerals Management (OMM) decisions and orders issued under subchapter B.
If you are adversely affected by an OMM official's final decision or order issued under 30 CFR chapter II, subchapter B, you may appeal that decision or order to the Interior Board of Land Appeals (IBLA). Your appeal must conform with the procedures found in this subpart and 43 CFR part 4, subpart E. A request for reconsideration of an MMS decision concerning a lease bid, authorized in 30 CFR 256.47(e)(3) and 281.21(a)(1), or a deep water field determination, authorized in 30 CFR 203.79(a) and 30 CFR 260.110(d)(2), is not subject to the procedures found in this part.
You must file your appeal within 60 days after you receive OMM's final decision or order. The 60-day time period applies rather than the time period provided in 43 CFR 4.411(a). A decision or order is received on the date you sign a receipt confirming delivery or, if there is no receipt, the date otherwise documented.
For your appeal to be filed, MMS must receive all of the following within 60 days after you receive the decision or order:
(a) A written Notice of Appeal together with a copy of the decision or order you are appealing in the office of the OMM officer that issued the decision or order. You cannot extend the 60-day period for that office to receive your Notice of Appeal; and
(b) A nonrefundable processing fee of $150 paid with the Notice of Appeal.
(1) Identify the order you are appealing on the check or other form of payment you use to pay the processing fee.
(2) You cannot extend the 60-day period for payment of the processing fee.
(3) You must pay the processing fee to MMS following the requirements for making payments found in 30 CFR 218.51. You are not required to use
You cannot obtain an extension of time to file the Notice of Appeal. See 43 CFR 4.411(c).
(a) You may seek informal resolution with the issuing officer's next level supervisor during the 60-day period established in § 290.3.
(b) Nothing in this subpart precludes resolution by settlement of any appeal or matter pending in the administrative process after the 60-day period established in § 290.3.
(a) The decision or order is effective during the 60-day period for filing an appeal under § 290.3 unless:
(1) OMM notifies you that the decision or order, or some portion of it, is suspended during this period because there is no likelihood of immediate and irreparable harm to human life, the environment, any mineral deposit, or property; or
(2) You post a surety bond under 30 CFR 250.1409 pending the appeal challenging an order to pay a civil penalty.
(b) This section applies rather than 43 CFR 4.21(a) for appeals of OMM orders.
(c) After you file your appeal, IBLA may grant a stay of a decision or order under 43 CFR 4.21(b); however, a decision or order remains in effect until IBLA grants your request for a stay of the decision or order under appeal.
(a) If you receive a decision or order issued under chapter II, subchapter B, you must appeal that decision or order to IBLA under 43 CFR part 4, subpart E to exhaust administrative remedies.
(b) This section does not apply if the Assistant Secretary for Land and Minerals Management or the IBLA makes a decision or order immediately effective notwithstanding an appeal.
This subpart tells you how to appeal Minerals Management Service (MMS) or delegated State orders concerning reporting to the MMS Royalty Management Program (RMP) and the payment of royalties and other payments due under leases subject to this subpart.
This subpart applies to:
(a) All Federal mineral leases onshore and on the Outer Continental Shelf (OCS); and
(b) All federally-administered mineral leases on Indian tribal and individual Indian mineral owners’ lands, regardless of the statutory authority under which the lease was issued or maintained.
(1) The principal amount of any royalty, minimum royalty, rental, bonus, net profit share or proceed of sale;
(2) Any interest; or
(3) Any civil or criminal penalty.
(1) Contract;
(2) Net profit share arrangement;
(3) Joint venture; or
(4) Agreement the Secretary approves under the Indian Mineral Development Act, 25 U.S.C. 2101
(1) A lessee's, designee's or payor's duty to:
(i) Deliver oil or gas royalty in kind; or
(ii) Make a lease-related payment, including royalty, minimum royalty, rental, bonus, net profit share, proceeds of sale, interest, penalty, civil penalty, or assessment; and
(2) The Secretary's duty to:
(i) Take oil or gas royalty-in-kind; or
(ii) Make a lease-related payment, refund, offset, or credit, including royalty, minimum royalty, rental, bonus, net profit share, proceeds of sale, or interest.
(3) The obligations identified in paragraphs (1)(i) and (2)(i) of this definition are nonmonetary obligations. The obligations identified in paragraphs (1)(ii) and (2)(ii), including the requirement to compute the amount of such obligations, are monetary obligations.
(1) Order includes:
(i) An order to pay or to compute and pay; and
(ii) An MMS or delegated State decision to deny a lessee's, designee's, or payor's written request that asserts an obligation due the lessee, designee or payor.
(2) Order does not include:
(i) A non-binding request, information, or guidance, such as:
(A) Advice or guidance on how to report or pay, including a valuation determination, unless it contains mandatory or ordering language; and
(B) A policy determination;
(ii) A subpoena;
(iii) An order to pay that MMS issues to a refiner or other person involved in disposition of royalty taken in kind; or
(iv) A Notice of Noncompliance or a Notice of Civil Penalty issued under 30 U.S.C. 1719 and 30 CFR part 241, or a decision of an administrative law judge or of the IBLA following a hearing on the record on a Notice of Noncompliance or Notice of Civil Penalty.
(a) If you receive an order that adversely affects you or your lessee, you may appeal that order except as provided under § 290.104.
(b) If you are a lessee and you receive a Notice of Order, and if you contest the order, you may either appeal the order or join in your designee's appeal under § 290.106.
You may not appeal:
(a) An action that is not an order, as defined in this subpart; or
(b) A determination of the surety amount or financial solvency under 30 CFR part 243, subparts B or C.
(a) You may appeal an order to the Director, Minerals Management Service (MMS Director), by filing a Notice of Appeal in the office of the official issuing the order within 30 days from service of the order.
(1) Within the same 30-day period, you must file in the office of the official issuing the order a statement of
(2) If you are a designee, when you file your Notice of Appeal you must serve your Notice of Appeal on the lessees for the leases in the order you appealed.
(b) You may not request and will not receive an extension of time for filing the Notice of Appeal.
(c) If the office of the official issuing the order does not receive the Notice of Appeal within the time provided in paragraph (a) of this section, the Notice of Appeal will be considered timely if the office of the official issuing the order receives:
(1) The Notice of Appeal not later than 10 days after the required filing date; and
(2) The officer with whom the Notice of Appeal must be filed determines that the Notice of Appeal was transmitted to the proper office before the filing deadline in paragraph (a) of this section.
(d) If the Notice of Appeal is filed after the grace period provided in paragraph (c) of this section and was not transmitted to the proper office before the filing deadline in paragraph (a) of this section, the MMS Director will not consider the Notice of Appeal and the case will be closed.
(e) The officer with whom the Notice of Appeal is filed will send the appeal and accompanying papers to the MMS Director.
(f) The MMS Director will review the record and render a decision in the case.
(g) If an order involves Indian leases, the Deputy Commissioner of Indian Affairs will exercise the functions vested in the MMS Director.
(a) If you are a lessee, and your designee files an appeal under § 290.103, you may join in that appeal within 30 days after you receive your designee's Notice of Appeal under § 290.105(a)(2) by filing a Notice of Joinder with the office or official that issued the order.
(b) If you join in an appeal under paragraph (a) of this section, you are deemed to appeal the order jointly with the designee, but the designee must fulfill all requirements imposed on appellants under this subpart and 43 CFR part 4, subparts E and J. You may not file submissions or pleadings separately from the designee.
(c) If you are a lessee and you neither appeal nor join in your designee's appeal under this section, your designee's actions with respect to the appeal and any decisions in the appeal bind you.
(d) If you are a designee and you decide to discontinue participation in the appeal, you must serve written notice within 30 days before the next submission or pleading is due on:
(1) All lessees who have joined in the appeal under paragraph (a) of this section;
(2) The office or officer with whom any subsequent submissions or pleadings must be filed, including the IBLA; and
(3) All other parties to the appeal.
(e) If you have joined in the appeal under paragraph (a) of this section, and if the designee notifies you under paragraph (d) of this section that it declines to further pursue the appeal, you become an appellant and must then meet all requirements of this subpart and 43 CFR part 4, subparts E and J, as the appellant.
If your appeal involves monetary or nonmonetary obligations under Federal oil and gas leases, the rules concerning the effect of the Department not issuing a final decision in your appeal within the 33-month period prescribed under 30 U.S.C. 1724(h) are located in 43 CFR part 4, subpart J.
Any party to a case adversely affected by a final decision of the MMS Director or the Deputy Commissioner of Indian Affairs under this subpart shall have a right of appeal to the IBLA under the procedures provided in 43 CFR part 4, subpart E.
(a) If you are a party to an appeal under this subpart, and you need additional time after the appeal commences under 43 CFR 4.904 for any purpose:
(1) You may obtain an extension of time under this section; and
(2) You must submit a written request for an extension of time to:
(i) The office or official with whom you must file a document before the required filing date; or
(ii) If you are not seeking an extension of time to file a document, to the office or official before whom the appeal is pending.
(b) If you are an appellant, and if your appeal involves monetary or nonmonetary obligations under Federal oil and gas leases, you must agree in writing in your request to extend the period in which the Department must issue a final decision in your appeal under 30 U.S.C. 1724(h) and 43 CFR 4.906, by the amount of time for which you are requesting an extension.
(c) If you are any other party to an appeal involving monetary or nonmonetary obligations under Federal oil and gas leases, the office or official with whom you must file the request may require you to submit a written agreement signed by the appellant to extend the period in which the Department must issue a final decision in the appeal under 43 CFR 4.906, by the amount of time for which you are requesting an extension.
(d) The office or official with whom you must file your request may decline any request for an extension of time.
(e) You must serve your request on all parties to the appeal.
(a) To exhaust administrative remedies, you must appeal an MMS Royalty Management Program (RMP) or delegated State order:
(1) To the MMS Director (or the Deputy Commissioner of Indian Affairs when Indian lands are involved); and
(2) Subsequently to the Interior Board of Land Appeals under 30 CFR part 290, subpart B, and 43 CFR part 4.
(b) This section does not apply if an order was made effective by:
(1) The Director;
(2) The Assistant Secretary for Land and Minerals Management;
(3) The Assistant Secretary for Indian Affairs; or
(4) The Interior Board of Land Appeals under 43 CFR part 4.
(a)
(b)
(2) The addressee of record for serving official correspondence on anyone required to report energy and mineral resources removed from Federal and Indian leases to the RMP Production Accounting and Auditing System is the most recent position title, department name and address, or individual name and address that RMP has in its records for the reporter/payor. The reporter/payor is responsible for notifying RMP, in writing, of any addressee changes.
(3) The addressee of record for serving official correspondence concerning
(4) The addressee of record for serving official correspondence in connection with reviews and audits of payor records is the position title, department name and address, or individual name and address designated, in writing, by the company at the initiation of the audit, or the most recent addressee that was specified, in writing, by the payor.
(5) The addressee of record for serving official correspondence relating to reporting on the “Report of Sales and Royalty Remittance” (Form MMS-2014) is the most recent position title, department name and address, or individual name and address specified, in writing, by the payor. The payor is responsible for notifying RMP, in writing, of any addressee changes.
(6) The addressee of record for serving official correspondence in connection with remittances pertaining to rental and bonuses from nonproducing Federal leases is the most recent position title, department name and address, or individual name and address maintained in RMP records. The payor is responsible for notifying RMP, in writing, of any addressee changes.
(7) The addressee of record for serving official correspondence including orders, demands, invoices, or decisions, and other actions identified with payors reporting to the RMP Auditing and Financial System not identified above is the position title, department name and address or individual name and address for the payor identified on the most recent Payor Confirmation Report (Report No. RPI140R1) of a Payor Information Form (PIF) (Form MMS-4025 or Form MMS-4030) returned by RMP to the payor for the Federal or Indian lease (see 30 CFR 210.51 and 210.201).
(8) If correspondence applies to more than one category identified in paragraphs (b)(1) through (7) of this section, MMS may serve the official correspondence in accordance with the requirements of any one paragraph.
(c)
(d)
(2) This provision covers such situations as nondelivery because the addressee has moved without filing a forwarding address, the forwarding order had expired, delivery was expressly refused, or the document was unclaimed where the attempt to deliver is substantiated by U.S. Postal Service authorities.
Sec. 201, Pub. L. 95-87, 91 Stat. 445, 30 U.S.C. 1201 et seq.
For special rules applicable to hearings, appeals, and other review procedures relating to surface mining control and reclamation within the jurisdiction of administrative law judges and the Interior Board of Surface Mining and Reclamation Appeals, Office of Hearings and Appeals, see Subpart L of part 4 of subtitle A—Office of the Secretary of the Interior, of title 43 CFR. Subpart A of part 4 and all of the general rules in subpart B of part 4 not inconsistent with the special rules in subpart L of part 4 are also applicable to such hearings, appeals and other review proceedings.
42 U.S.C. 10303.
The regulations in this part are issued pursuant to title I of the Water Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97) which authorizes appropriations to, and confers authority upon, the Secretary of the Interior to promote a national program of water-resources research.
The State Water Research Institute Program, as authorized by section 104 of the Act, has been established as a component of the U.S. Geological Survey (USGS). Secretary of the Interior has delegated to the Director of the USGS authority to take the actions and make the determinations that, under the Act, are the responsibility of the Secretary.
(a) The information collection requirements contained in sections 401.11 and 401.19 have been approved by the Office of Management and Budget under 44 U.S.C. 3501 et seq. and assigned clearance number 1028-0044. The information will be used to support water related research and provide performance reports on accomplishments achieved under Pub. L. 98-242, 98 Stat. 97 (42 U.S.C. 10303). This information allows the agency to determine compliance with the objectives and criteria of the grant programs. Response is mandatory in accordance with 30 CFR 401.11 and 401.19.
(b) Public reporting burden for the collection of information is estimated to average 84 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate, or any other suggestions for reducing the burden, to Paperwork Management Officer, U.S. Geological Survey, Paperwork Management Section MS 208, Reston, Virginia 22092 and the Office of Management and Budget, Paperwork Reduction Project (1028-0044), Washington, DC 20503.
(a) As a condition of recognition as an established institute under the provisions of this chapter, each institute shall provide to the Director written evidence that it conforms to the requirements of subsection 104(a) of the Act, in that:
(1) The institute is established at the college or university in the State that was established in accordance with the Act of July 21, 1862 (12 Stat. 503; 7 U.S.C. 301ff),
(2) If established at some other institution, the institute is at a college or university that has been designated by act of the legislature for the purposes of the Act, or;
(3) If there is more than one “land-grant” institution in the State, and no designation has been made according to paragraph (a)(2) of this section, the institute has been established at the one such institution designated by the Governor of the State to participate in the program, or;
(4) The institute has been designated as an interstate or regional institute by two or more cooperating States as provided in the Act.
(b) The certification of designation made pursuant to paragraph (a) of this section shall originate following the issuance of these regulations, be signed by the highest ranking officer of the college or university at which the institute is established and be submitted to the Director within 90 days of the effective date of these regulations. It shall be accompanied either by the evidence of establishment under the provisions of 30 CFR part 401 or by new evidence of establishment made pursuant to these regulations.
(c) Any institute not previously established under the provisions of the Water Resources Act of 1964 (Pub. L. 88-379, 78 Stat. 331) or the Water Research and Development Act of 1978 (Pub. L. 95-467, 92 Stat. 1305) shall also, in addition to the annual program application specified in § 401.11 of this chapter, submit to the Director the following information:
(1) Evidence of the appointment by the governing authority of the college or university of an officer to receive and account for all funds paid under the provisions of the Act and to make annual reports to the granting agency on work accomplished; and
(2) A management plan for meeting the requirements of the evaluation mandated by § 401.26.
(a) Release of grant funds to participating institutes is conditioned on the ability of each receiving institute to plan, conduct, or otherwise arrange for:
(1) Competent research, investigations, and experiments of either a basic or practical nature, or both, in relation to water resources;
(2) Promotion of the dissemination and application of the results of these efforts; and
(3) Assistance in the training of scientists in relevant fields of endeavor to water resources through the research, investigations, and experiments.
(b) Such research, investigations, experiments and training may include:
(1) Aspects of the hydrologic cycle;
(2) Supply and demand;
(3) Demineralization of saline and other impaired waters;
(4) Conservation and best use of available supplies of water and methods of increasing such supplies;
(5) Water reuse;
(6) Depletion and degradation of ground-water supplies;
(7) Improvements in the productivity of water when used for agricultural, municipal, and commercial purposes;
(8) The economic, legal, engineering, social, recreational, biological, geographical, ecological, or other aspects of water problems;
(9) Scientific information dissemination activities, including identifying, assembling, and interpreting the results of scientific research on water resources problems, and ;
(10) Providing means for improved communication of research results, having due regard for the varying conditions and needs of the respective States and regions.
(c) An institute shall cooperate closely with other colleges and universities in the State that have demonstrated capabilities for research, information dissemination and graduate training in the development of its program. For purposes of financial management, reporting and other research program management and administration activities, the institutes shall be responsible for performance of the activities of other participating institutions.
(d) Each institute shall cooperate closely with other institutes and other research organizations in the region to increase the effectiveness of the institutes, to coordinate their activities, and to avoid undue duplication of effort.
(a) Subject to the availability of appropriated funds, but not to exceed a total of $10 million, an equal amount of dollars will be available to each qualified institute in each fiscal year to assist it in carrying out the purposes of the Act. If the full amount of the appropriated funds is not obligated by the close of the fiscal year for which they were appropriated, the remaining funds shall be made available in the succeeding fiscal year to support competitively selected research projects under the terms of section 104(g) of the Act. Selection and approval of such projects shall be based on criteria to be determined by the Director. Announcement of such criteria shall be made by notice in the
(b) The granting agency will annually make available to qualified institutes instructions for the submittal of applications for grants. The instructions will include information pertinent only to a single fiscal year, such as the closing date for applications and the amount of funds initially available to each institute. They also will include notification of the provisions and assurances necessary to ensure that administration of the grant will be conducted in compliance with this chapter and other Federal laws and regulations applicable to grants to institutions of higher learning.
(c) In making its application for funds to which it is entitled under the Act, each institute shall use and follow the standard form for Federal assistance (SF 424, Federal Assistance). No preapplication is required. The institute shall include in section IV of Standard Form 424 evidence that its application was:
(1) Developed in close consultation and collaboration with senior personnel of the State's department of water resources or similar agencies, other leading water resources officials within the State, and interested members of the public;
(2) Coordinated with other institutes in the region for the purposes of avoiding duplication of effort and encouraging regional cooperation in research areas of water management, development, and conservation that have a regional or national character; and
(3) Reviewed for technical merit of its research components by qualified scientists.
(d) Each application shall further include:
(1) A financial plan relating expenditures to scheduled activity and rate of effort to be expended and indicating the times at which there will be need for specified amounts of Federal funds; and
(2) A description of the institute's arrangements for development, administration, and technical oversight of the research program.
(e) Each annual program application is to include separately identifiable proposals for conduct of research to meet the needs of the State and region. Such proposals must set forth for each project:
(1) The nature, scope and objectives of the project to be undertaken;
(2) Its importance to the State, region, or Nation; its relation to other known research projects already completed or in progress; and the anticipated applicability of the research results;
(3) The period during which it will be pursued;
(4) The names and qualifications of the senior professional personnel who will direct and conduct the project;
(5) Its estimated costs, with a breakdown of the costs per year; and
(6) The extent of which it will provide opportunity for the training of scientists.
(f) Each program application shall contain a plan for disseminating information on the results of research and promoting their application. Plans which require the use of grant funds shall contain:
(1) Definition of the topics for dissemination;
(2) Identification of the target audiences for dissemination;
(3) Strategies for accomplishing the dissemination;
(4) Duties and qualifications of the personnel to be involved;
(5) Estimated costs of each identifiable element of the plan; and
(6) Identification of cooperating entities.
(g) The application shall provide assurance that non-Federal dollars will be available to share the costs of the proposed program. The Federal funds are to be matched on a basis of no less than two non-Federal dollars for each Federal dollar, unless this matching requirement has been waived.
(h) The granting agency will evaluate the proposals for consistency with the provisions of its instructions and this chapter and within no more than 90 days request any revisions and additions necessary for such consistency.
(a) Upon approval of each fiscal year's proposed program, the granting agency will transmit to the grantee an award which will incorporate the application and assurances.
(b) The grant is effective and constitutes an obligation of Federal funds in the amount and for the purpose stated in the award document at the time of the Director's signature.
(c)(1) Acceptance of the award document certifies the grantee's assurance that the grant will be administered in compliance with OMB regulations, policies, guidelines, and requirements as described in:
(i) Circular No. A-21, revised, Cost Principles of Educational Institutions;
(ii) Memorandum No. M-92-01, Coordination of Water Resources Information;
(iii) Circular No. A-88, revised, Indirect Cost Rates, Audit and Audit Follow-up at Educational Institutions;
(iv) Circular No. A-110, Uniform Administrative Requirements for Grants and Agreements with Institutions of Higher Education, Hospitals and other Nonprofit Organizations; and
(v) Circular No. A-124, Patents—Small Business Firms and Nonprofit Organizations.
(2) Copies of the documents listed in paragraph (c)(1) of this section shall be available from the granting agency.
(a) The institutes are encouraged to publish, as technical reports or in the professional literature, the findings, results, and conclusions relating to separately identifiable research projects undertaken pursuant to the Act.
(b) Each institute shall submit to the granting agency, by a date to be specified in the award document, an annual program report which provides:
(1) A statement concerning the relationship of the institute's program to the water problems and issues of the State;
(2) A synopsis of the objectives, methods, and conclusions of each project completed within the period covered;
(3) A progress report on each project continuing into the subsequent fiscal year;
(4) Citations of all reports, papers, publications or other communicable products resulting from each project completed or in progress;
(5) A description of all activities undertaken for the purpose of promoting the application of research results;
(6) A description of cooperative arrangements with other educational institutions, State agencies, and others.
(c) One manuscript of reproducible quality and two copies of the annual program report shall be furnished to the granting agency. One copy of a complete report on the objectives, methods, and conclusions of each research project shall be maintained by the institute and open to inspection.
(d) Appropriate acknowledgment shall be given by institutes to the granting agency's participation in financing activities carried out under provisions of the Act. Such acknowledgment shall be included in all reports, publications, news releases, and other information media developed by institutes and others to publicize, describe, or report upon accomplishments and activities of the program.
(e) An original and two copies of the final “Financial Status Report,” SF 269, shall be furnished to the granting agency within 90 days of completion of the grant period.
(a) Within 2 years of the date of its certification according to the provisions of § 401.6, each institute will be evaluated for the purpose of determining whether the national interest warrants its continued support under the provisions of the Act. That determination shall be based on:
(1) The quality and relevance of its water resources research as funded under the Act;
(2) Its effectiveness as an institution for planning, conducting, or arranging for research;
(3) Its demonstrated performance in making research results available to users in the State and elsewhere; and
(4) Its demonstrated record in providing for the training of scientists through student involvement in its research program.
(b) An evaluation team, selected by the granting agency on the basis of the members’ knowledge of water research and administration, shall evaluate each institute, and may with the concurrence of the granting agency, visit such institutes as it considers necessary. The team is to include at least one individual from each of the following categories:
(1) Employees of the Department of the Interior;
(2) University faculty or other professionals with relevant experience in the conduct of water resources research;
(3) Former directors of water research institutes; and
(4) University faculty or other professionals with relevant experience in information transfer.
(c) The granting agency may request recommendations for team selections from the National Research Council/National Academy of Sciences and from other organizations whose members include the types of individuals cited in paragraph (b) of this section.
(d) The granting agency shall, as an administrative cost, provide the funds for travel and per diem expense of the team members, within the maximum limits allowable under Federal travel regulations (41 CFR subtitle F).
(e) The granting agency has the right to select dates for evaluation visits, and notice of the team's visit shall be provided to the institute being evaluated at least 60 days in advance.
(f) It shall be the responsibility of each institute to provide such documentation of its activities and accomplishments as the granting agency and
(g) The team shall, within 90 days after completion of its evaluation, submit a written report of its findings to the granting agency for transmittal to the institute. If an institute is found to have deficiencies in meeting the objectives of the Act, it shall be allowed 1 year to correct them and to report such action to the granting agency. The decision as to the institute's eligibility to receive further funding will rest with the granting agency.
(h) After the initial evaluation, each institute shall be reevaluated at least every 5 years.
Secs. 105 and 106, Pub. L. 98-242, 98 Stat. 97 (42 U.S.C. 10304 and 10305).
The regulations in this part are issued pursuant to title I of the Water Resources Research Act of 1984 (Pub. L. 98-242, 98 Stat. 97), which authorizes appropriations to, and confers authority upon, the Secretary of the Interior to promote national programs of water-resources research and technology development.
The Water-Resources Research Program and the Water-Resources Technology Development Program, as authorized by sections 105 and 106 of the Act (42 U.S.C. 10304 and 10305), have been established as components of the USGS. The Secretary of the Interior has delegated to the Director of the USGS authority to take actions and make the determinations that, under the Act, are the responsibility of the Secretary.
(a)
(b)
(c)
(d)
The information-collection requirements contained in sections 402.10, 402.11, and 402.15 have been approved by the OMB under 44 U.S.C. 3501
(a) Subject to the availability of appropriated funds, the Water-Resources Research Program will provide support, in the form of a dollar-for-dollar matching grant, to educational institutions, private foundations, private firms, individuals, and agencies of local or State governments for research concerning any aspect of a water-resource related problem deemed to be in the national interest. Federal agencies are excluded from receiving matching grants. Grants may be awarded on other than a dollar-for-dollar matching basis in cases where the USGS determines that research on a high-priority subject is of a basic nature that otherwise would not be undertaken.
(b) The types of research to be undertaken under this program are listed below, without indication of priority:
(1) Aspects of the hydrologic cycle;
(2) Supply and demand for water;
(3) Demineralization of saline and other impaired waters;
(4) Conservation and best use of available supplies of water and methods of increasing such supplies;
(5) Water reuse;
(6) Depletion and degradation of groundwater supplies;
(7) Improvements in the productivity of water when used for agricultural, municipal, and commercial purposes; and
(8) The economic, legal, engineering, social, recreational, biological, geographic, ecological, and other aspects of water problems.
(9) Scientific information-dissemination activities, including identifying, assembling, and interpreting the results of scientific and engineering research on water-resources problems.
(10) Providing means for improved communications of research results, having due regard for the varying conditions and needs for the respective States and regions.
(a) Subject to the availability of appropriated funds, the Water-Resources Technology Development Program will provide funds in the form of grants or contracts to educational institutions, private firms, private foundations, individuals, and agencies of local or State governments for technology development concerning any aspect of water-related technology deemed to be of State, regional, and national importance, including technology associated with improvement of waters of impaired quality and the operation of test facilities. Federal agencies are excluded from receiving grants or contracts. The types of technology-development to be undertaken under this program shall include paragraphs 1 through 10 of § 402.6(b).
(b) The USGS may establish any condition for the matching of funds by the recipient of any grant or cost-sharing under a contract under the technology-development program which the USGS considers to be in the best interest of the Nation.
(a) Only those applications for grants that are in response to and meet the guidelines of specific USGS announcements will be considered for funding appropriated for this program.
(b) The USGS program announcements will identify priorities, matching requirements, particular areas of interest, criteria for evaluation, OMB regulations as appropriate, assurances, closing date, and proposal submittal instructions. Program announcements may also include criteria for high-priority subjects of a basic nature that may be funded on other than a dollar-for-dollar basis. Program announcements will be distributed to names on the current USGS mailing list for the
(c) Notification of the availability of the program announcement will be published in the Commerce Business Daily and/or
(d) The application for funds must be signed by an individual or official authorized to commit the applicant and it must contain:
(1) A Standard Form 424 “Federal Assistance,” sections I and II completed by applicant, used as the cover sheet for each proposal.
(2) A project summary of no more than one typed, single-spaced page providing the following specific information:
(i) Identification of the water or water-related problems and the problem-solution approach;
(ii) Identification of the proposed scientific contribution of the problem solution;
(iii) Concise statement of the specific objectives of the project;
(iv) Identification of the approach to be used to accomplish the work; and
(v) Identification of potential users of the proposed work.
(3) Narrative information, as specified in the published program announcement, such as project title, project objectives, background information, research tasks, methodology to conduct the research task, the relevancy of the proposed project to water-resources problems, qualifications of the principal investigators and their organizations, and proposed budget with supporting information sufficient to allow evaluation of costs.
(a) Grant awards will be used to support those portions of the program for which the principal purpose is other than as described in § 402.11(b). Program announcements and applications will be governed by the same procedures provided in § 402.10.
(b) If it is determined that the principal purpose of a planned award (or awards) is to acquire goods or services for the direct benefit or use of the Government, the action must be regarded as a procurement contract. A competitive solicitation prepared in accordance with applicable acquisition regulations will be issued to interested parties. Notification of the availability of any contract solicitation will be published in the Commerce Business Daily, unless waived in accordance with § 5.202 of the Federal Acquisition Regulation (FAR). Contracts may be awarded without full and open competition only if justified in accordance with FAR subpart 6.3.
(a)
(2) Grant applications with low technical ratings will be screened out, and the remaining grant applications will be rank-ordered by review panels.
(3) USGS program officials will compile a single, consolidated rank-ordered list of the grant applications based on technical scoring, program needs and published priorities, and the available Federal funds.
(b)
(a) After the conclusion of negotiations, the USGS will transmit a grant or contract-award document, as appropriate, setting forth the terms of the award.
(b)
(c)
(a) Grantees or contractors will be required to submit the following technical reports to the USGS address identified under the terms and conditions of each award.
(1)
(2)
(3)
(4)
(b) Grantees or contractors will be required to submit financial, administrative, and closeout reports as identified under the terms of each award. Reporting requirements will conform to the procedures described in the Departmental Manual of the Department of the Interior at 505 DM 1-5.
(c) Contracts for technology-development projects may also require delivery of hardware items produced and/or specifications, drawings, test results, or other data describing the funded technology.
Pub. L. 86-777, approved Sept. 13, 1960, 74 Stat. 918 (50 U.S.C. 167-167n).
The purpose of this part 601 is to establish procedures governing the sale of helium and related services by the Bureau of Mines, and the rental of helium containers from the Bureau of Mines.
(a)
(b) [Reserved]
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
(q)
(a) Any prospective helium purchaser may make application to the Bureau to become a purchaser of helium, and, if desired, rent containers from the bureau and, upon meeting the requirements of this part and upon execution of a purchase (and container rental) contract with the Bureau, may purchase helium (and rent containers) from the Bureau. To be eligible, a prospective purchaser must: demonstrate adequate financial resources to pay for helium and helium-related services in advance, hold a certificate of competency and/or a determination of eligibility from the Small Business Administration if the prospective purchaser is a small business concern and is determined to be nonresponsible and/or ineligible by the contracting officer, and be otherwise qualified and eligible to enter into a Bureau contract under applicable laws and regulations.
(b) The information collection requirement contained in this paragraph has been approved by the Office of Management and Budget under 44 U.S.C. 3507 and assigned clearance number 1032-0111. The information is being collected to identify firms desiring to enter into a contract. This information will be used to complete contract documents and establish cash advance required. The obligation to respond is required to obtain a benefit.
(c) The contract shall include, among other things, duties and responsibilities of the parties, definitions, term, minimum contract volume, and other conditions, such as advance payments, deposits, surety bonds, repurchase rights of the Government, liabilities, reservations with respect to sales and deliveries, power of inspection, notification to repurchasers, violations and penalties, cancellation and assignment of contract, termination, general provisions, and standard provisions.
(d) Application forms are available upon written request from Division of Helium Operations, 1100 S. Fillmore St., Amarillo, Texas 79101. Applicable contract form(s) and Schedule will be included for examination by the prospective purchaser.
(e) Upon approval by the Contracting Officer of the returned application, the contract will become effective when executed by both parties.
(a) The Schedule of Prices and Charges (Schedule) is published by the Bureau of Mines, Division of Helium Operations, and is periodically updated. The Schedule is available upon request from the Division of Helium Operations, 1100 S. Fillmore St., Amarillo, Texas 79101, telephone 806-376-2638 or FTS 735-1638. The Schedule shows prices and charges for helium, ordinary related services, use or rental of Bureau-owned helium containers or equipment, cash advance, and deposit required, and bonds and/or insurance to guarantee return of containers.
(b) Terms and conditions under which products and services can be acquired under contract pursuant to this part are shown in appendix 1 to the Schedule. The terms and conditions are reviewed at least annually, and are revised as required.
(c) Revisions to the Schedule are determined at least annually by the Division of Helium Operations in accordance with Office of Management and
(a) The purchase price of Grade-A helium shipped f.o.b. origin shall be the price stated in the Schedule that is in effect on the date the helium is shipped from the helium plant.
(b) [Reserved]
(c) The purchase price of Grade-A helium shipped f.o.b. destination shall be the price stated in the Schedule that is in effect on the date the helium is shipped from the helium plant plus any service charges, container charges, transportation charges, and other charges incurred in making such delivery. Delivery of helium f.o.b. destination is made only in Bureau-furnished containers.
In addition to the purchase price of helium, the following charges for services and use of equipment rented from the Bureau shall be paid by the purchaser.
(a)
(b)
(c)
(d)
Contracts for the purchase of helium or for the rent of Bureau-owned shipping containers which are in effect on the effective date of the amended regulations in this part shall remain in effect, subject to the terms and conditions of the amended regulations in this part, for a period of not more than 90 days after the effective date of these amended regulations or until replaced by new contract or contracts as described in these amended regulations, should such replacement occur prior to expiration of the 90 days. In the event that purchaser does not enter into replacement contract or contracts within 90 days after effective date of these regulations, the existing contract(s) shall terminate and purchaser shall pay any sums due Bureau under terms of the contracts and shall return any Bureau-owned shipping containers outstanding under any container rent contract so terminated.
(a)
(b)
The regulations in this part are applicable to Federal agencies procuring helium or services from Bureau or using containers furnished by Bureau;
30 U.S.C. 1221-1230; Pub. L. 98-409; Pub. L. 100-483.
This part sets forth policies and procedures for the assistance of institutions of higher learning that have been designated as State Mining and Mineral Resources Research Institutes and for the support of mining and mineral resources research at these institutions through specialized generic mineral technology research centers.
The objectives of the assistance provided by the Mining and Mineral Resources Research Institute program are:
(a) To support research and training in mining and mineral resources problems related to the mission of the Department of the Interior;
(b) To improve the advanced training of mineral scientists and engineers through grants which encourage State and industry support of mineral education;
(c) To support, and encourage support of, research centers of generic expertise in mineral technology;
(d) To assist the States in carrying on the work of competent and qualified mining and mineral resources research institutes; and
(e) To provide support for graduate and postdoctoral students in mining and mineral resources disciplines including mining engineering, extractive metallurgy, geology, reclamation, engineering, economics, chemistry, physics, biology, ecology, and others.
The authority for this program is the Mining and Mineral Resources Research Program Act of 1984 and the Mining and Mineral Resources Research Institute Amendments of 1988.
(a) 30 U.S.C. 1221 authorizes the Secretary to make grants to assist States on a matching basis in carrying on the work of competent and qualified mining and mineral resources research institutes.
(b) 30 U.S.C. 1222 authorizes the Secretary to make grants to the institutes for specific research and demonstration projects, and for research into any aspects of mining and mineral resources problems related to the mission of the Department of the Interior deemed desirable and not otherwise under study.
(c) 30 U.S.C. 1229 authorizes the Secretary to appoint an Advisory Committee on Mining and Mineral Resources Research jointly chaired by the Assistant Secretary of the Interior responsible for minerals and mining and a committee member elected by the Committee from among those members who are not Federal employees.
Responsibility for administration of the Mining and Mineral Resources Research Institute Program is assigned to the Director of the Bureau of Mines
As used in this part, the term—
Only institutions of higher learning (post-secondary institutions having graduate research programs) designated by the Secretary, after consultation with, and upon the advice of the Advisory Committee, as a State Mining and Mineral Resources Research Institute are eligible to receive funds under this program. Only one institution may be designated per State. To qualify as a mineral institute, institutions must meet all the following criteria as determined by the Advisory Committee:
(a) Be either a public college or university or, in a State not having an eligible public college or university, a private college or university in that State.
(b) Be recommended by the Governor of the State, as eligible, in the absence of contrary act by the legislature of the State.
(c) Have in existence a substantial program of graduate instruction and research in mining or mineral extraction or closely related fields which has a demonstrated history of achievement.
(d) Evidence institutional commitment to the purposes of the Act.
(e) Exhibit significant industrial cooperation in activities within the scope of the Act.
(f) Have in existence an engineering program in mining or minerals extraction that is accredited by the Accreditation Board for Engineering and Technology, or show evidence of equivalent institutional capability.
(g) Employ at least six full-time permanent faculty members in the department or component of the institution conducting instruction and research in mining and mineral extraction.
(h) Meet such other criteria as the Advisory Committee shall deem necessary or desirable.
(a) Each institution designated as mineral institute has the duty of planning and conducting mineral resources research. To carry out its responsibility, it shall appoint a mineral institute director from its faculty or staff, who is professionally qualified in minerals research and education.
(b) Mineral institute directors shall be responsible for preparation of allotment grant proposals; for the technical administration of allotment grant agreements; for periodic reporting to the Bureau of Mines; for the preparation and transmission to the Bureau of Mines of an annual institute status report; for providing such coordination as may be necessary between various departments, units, and individuals at that institution to achieve a focused minerals program of value to the mineral institute's State and region; for the coordination between and among the minerals programs of the several mineral institutes; for responding to requests for information regarding the minerals program at that institution from the Bureau of Mines, the Advisory Committee, and the public; and for the selection and transmission of the best research proposals from that institution for inclusion in the generic mineral technology center program.
Applications for annual allotment grants shall be submitted in response to an annual call for proposals issued by the Bureau of Mines to mineral institutes. To receive a new allotment grant, a mineral institute must have submitted all reports due and shall not have been found by the Secretary to have improperly diminished, lost, or misapplied funds previously received. Such funds shall be replaced by the State concerned and until so replaced no subsequent grant shall be allotted or paid to the institute of that State. Each allotment grant application shall be responsive to 30 U.S.C. 1221(b) and as a minimum shall consist of the following elements in duplicate:
(a) A completed Standard Form 424.
(b) A plan to provide for the training of individuals as mineral engineers and scientists under a curriculum appropriate to the field of mineral resources and mineral engineering and related fields.
(c) A budget to support that plan.
(d) Assurance that Federal funds will supplement and, to the extent practicable, increase the level of funds that would otherwise have been available for the purposes of the Act, and in no case supplant such funds.
(e) Such other information as is requested in the Call for Proposals.
All research supported under this program, except for that funded through allotment grants, is funded through established generic mineral technology centers (generic centers). Each generic center provides a focus for mineral research in a specific area of broad applicability across the minerals industry. Each generic center has the following characteristics:
(a) It is headquartered in one mineral institute with participation by one or more affiliate institutions.
(b) A generic center director supervises the operation of the center including the coordination of related projects; makes arrangements for an annual seminar; provides for operation of a reference center; makes recommendations to the Bureau of Mines
(c) A reference center serves as a centralized repository of literature concerning the generic research area and also is a repository of all periodic and final reports, dissertations, and contributions to the technical literature resulting from generic center research.
(d) An annual seminar provides opportunity for students and principal investigators to exchange ideas and present their latest research in the generic area.
(e) A Research Council, consisting of experts in the generic research area from industry, government and, where possible, academia, attends the annual seminars, receives periodic reports, evaluates research proposals, and provides recommendations to the Bureau of Mines on the program of the center.
(f) New proposals for research, submitted through generic center and mineral institute directors, are evaluated on a competitive basis, in writing, and through Council discussion.
Proposals may be submitted to the Bureau of Mines in any of the generic mineral technology areas through mineral institute and generic mineral technology center directors in response to an annual call for proposals which describes the format of the proposals. Proposals shall address the requirements of 30 U.S.C. 1222 (b) through (d) as detailed in the call for proposals. No portion of any research grant shall be applied to the acquisition by purchase or lease of any land or interests therein or the rental, purchase, construction, preservation or repair of any building.
Under 30 U.S.C. 1223(b), mineral institutes are authorized to conduct cooperative programs with other mineral institutes and with such other agencies and individuals as may contribute to the solution of the mining and mineral resource problems involved. Mineral institutes may utilize their funds to pay for projects at other institutions under the following limitations:
(a) The mineral institute director (for allotment grants) or the generic mineral technology center director (for research grants) for the institution awarded the funds by the Bureau, or the designated representative of the above, shall administer, conduct and supervise all funded programs.
(b) All proposals to fund noninstitute activities shall be specifically set forth in the grant proposal applications required under § 652.8 and § 652.10 and must be explicitly approved by the Bureau of Mines.
(c) All subgrants and subcontracts, service agreements, and interdivisional work authorizations shall be subject to the same terms and conditions as the grant.
(d) Copies of all agreements for funding of programs conducted by noninstitute organizations, universities, or individuals shall be made available to the Bureau of Mines upon request.
Performance under all grants shall be in accord with the terms and conditions set forth in OMB Circulars A-110 (General Administration), A-21 (Cost Principles), A-88 (Indirect Cost Rates and Audit), and all other applicable laws and regulations. Copies of the OMB circulars are available from Publications Services, 725 17th Street NW., Room 2200, Washington, DC 20503. All uses, products, processes, patents, and other developments under this program, with such exceptions as the Secretary may make in the public interest, are to be made promptly available to the public. Patentable inventions shall be governed by the provisions of Pub. L. 96-517.
The following reports are required from program participants:
(a)
(b)
(c)
(d)
(e)
(1)
This research has been supported by the Department of the Interior's Mineral Institute Program administered by the Bureau of Mines under allotment grant number
This research has been supported by the Department of the Interior's Mineral Institute Program administered by the Bureau of Mines through the Generic Mineral Technology Center for
The information collection requirements contained in this section have been approved by the Office of Management and Budget under 44 U.S.C. 3501
Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing the burden, to Office of Statistical Standards, Bureau of Mines, Washington, DC 20241; and to the Office of Management and Budget, Paperwork Reduction Project (OMB No. 1032-0116), Washington, DC 20503.
An Advisory Committee on Mining and Mineral Resources Research, appointed by the Secretary under 30 U.S.C. 1229, shall consult with and make recommendations to the Secretary on the operation of and the making of grants under this program and it shall determine the eligibility of a college or university to participate as a Mining and Mineral Resources Research Institute under the Act and make such recommendation to the Secretary.
In relation to the substantive scientific and administrative operations of grantees, the Bureau of Mines or the Advisory Committee may perform inspections of activities authorized and financed pursuant to these regulations. Such inspections may cover acceptability of progress, consistency with approved plans, and institute eligibility.
(a) The mineral institute and generic center directors are responsible for promptly notifying the Office of events which may require modification of grant agreements, such as:
(1) Rebudgetings,
(2) No-cost time extensions, or
(3) Changes in scope.
(b) Permission of the Office is also required for the following actions under a grant:
(1) Equipment purchase of $1000 or more,
(2) Property transfer, or
(3) Foreign travel.
If a mineral institute or generic mineral technology center does not follow the provisions and terms of a grant or does not fully implement a grant program, the Director may reduce the size of or may suspend or terminate a grant.
A list of CFR titles, subtitles, chapters, subchapters and parts and an alphabetical list of agencies publishing in the CFR are included in the CFR Index and Finding Aids volume to the Code of Federal Regulations which is published separately and revised annually.
Material Approved for Incorporation by Reference
Table of CFR Titles and Chapters
Alphabetical List of Agencies Appearing in the CFR
Redesignation Table
List of CFR Sections Affected
The Director of the Federal Register has approved under 5 U.S.C. 552(a) and 1 CFR Part 51 the incorporation by reference of the following publications. This list contains only those incorporations by reference effective as of the revision date of this volume. Incorporations by reference found within a regulation are effective upon the effective date of that regulation. For more information on incorporation by reference, see the preliminary pages of this volume.
At 53 FR 10688, Apr. 1, 1988, 30 CFR part 250 and subpart N of part 256 were restructured and consolidated into revised 30 CFR part 250. For the convenience of the user, the following table shows the relationship of the old CFR section numbers and multitier rules to the new part 250 sections.
All changes in this volume of the Code of Federal Regulations which were made by documents published in the
For the period before January 1, 1986, see the “List of Sections Affected, 1949-1963, 1964-1972, 1973-1985” published in seven separate volumes.