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Title 30—
For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of Federal Regulations publication program is under the direction of Michael L. White, assisted by Ann Worley.
(This book contains parts 200 to 699)
25 U.S.C. 396
(1) Located in a water depth of at least 200 meters and in the Gulf of Mexico (GOM) west of 87 degrees, 30 minutes West longitude;
(2) That includes one or more pre-Act leases; and
(3) From which no current pre-Act lease produced, other than test production, before November 28, 1995.
(1) You begin drilling on or after March 26, 2003, and before May 3, 2009, on a lease that is located in water partly or entirely less than 200 meters deep and that is not a non-converted lease, or on or after May 18, 2007, and before May 3, 2013, on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep;
(2) You begin drilling before your lease produces gas or oil from a well with a perforated interval the top of which is at least 18,000 feet true vertical depth subsea (TVD SS), (
(3) You drill to at least 18,000 feet TVD SS with a target reservoir on your lease, identified from seismic and related data, deeper than that depth;
(4) Fails to meet the producibility requirements of 30 CFR part 250, subpart A, and does not produce gas or oil, or meets those producibility requirements and MMS agrees it is not commercially producible; and
(5) For which you have provided the notices and information required under § 203.47.
(1) Located in a planning area offshore Alaska; or
(2) Located in the GOM in a water depth of at least 200 meters and wholly west of 87 degrees, 30 minutes West longitude, and were issued in a sale held after November 28, 2000.
(1) Is issued as part of an OCS lease sale held after November 28, 1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
(1) You must propose the project in a Development and Production Plan, a Development Operations Coordination Document (DOCD), or a Supplement to a DOCD, approved by the Secretary of the Interior after November 28, 1995.
(2) The project must be located on either:
(i) A pre-Act lease in the GOM, or a lease in the GOM issued in a sale held after November 28, 2000, located wholly west of 87 degrees, 30 minutes West longitude; or
(ii) A lease in a planning area offshore Alaska.
(3) On a pre-Act lease in the GOM, the project:
(i) Must significantly increase the ultimate recovery of resources from one or more reservoirs that have not previously produced (extending recovery from reservoirs already in production does not constitute a significant increase); and
(ii) Must involve a substantial capital investment (e.g., fixed-leg platform, subsea template and manifold, tension-leg platform, multiple well project, etc.).
(4) For a lease issued in a planning area offshore Alaska, or in the GOM after November 28, 2000, the project must involve a new well drilled into a reservoir that has not previously produced.
(5) On a lease in the GOM, the project must not include a reservoir the production from which an RSV under §§ 203.30 through 203.36 or §§ 203.40 through 203.48 would be applied.
(1) Before the date which is 5 years after the lease issuance date on a non-converted lease; or
(2) Before May 3, 2009, on all other leases located in water partly or entirely less than 200 meters deep; or
(3) Before May 3, 2013, on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep.
(1) On or after the date which is 5 years after the lease issuance date on a non-converted lease; or
(2) On or after May 3, 2009, on all other leases located in water partly or entirely less than 200 meters deep; or
(3) On or after May 3, 2013, on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep.
(1) Results from a sale held before November 28, 1995;
(2) Is located in the GOM in water depths of 200 meters or deeper; and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude.
(1) On a lease that is located in water partly or entirely less than 200 meters deep that is not a non-converted lease, a deep well for which drilling began on or after March 26, 2003, that produces natural gas (other than test production), including gas associated with oil production, before May 3, 2009, and for which you have met the requirements prescribed in § 203.44;
(2) On a non-converted lease, a deep well that produces natural gas (other than test production) before the date which is 5 years after the lease
(3) On a lease that is located in water entirely more than 200 meters but entirely less than 400 meters deep, a deep well for which drilling began on or after May 18, 2007, that produces natural gas (other than test production), including gas associated with oil production before May 3, 2013, and for which you have met the requirements prescribed in § 203.44.
(1) On a lease that is located in water partly or entirely less than 200 meters deep that is not a non-converted lease, an ultra-deep well for which drilling began on or after March 26, 2003, that produces natural gas (other than test production), including gas associated with oil production, and for which you have met the requirements prescribed in § 203.35 or § 203.44, as applicable; or
(2) On a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep, or on a non-converted lease, an ultra-deep well for which drilling began on or after May 18, 2007, that produces natural gas (other than test production), including gas associated with oil production, and for which you have met the requirements prescribed in § 203.35.
(1) We have rejected your application;
(2) We have granted relief but you want a larger suspension volume;
(3) We withdraw approval; or
(4) You renounce royalty relief.
(1) Is issued as part of an OCS lease sale held after November 28, 2000;
(2) Is in locations or planning areas specified in a particular Notice of OCS Lease Sale offering that lease; and
(3) Is offered subject to a royalty suspension specified in a Notice of OCS Lease Sale published in the
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 and the Energy Policy Act of 2005, Public Law 109-058 authorizes us to grant royalty relief in four 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 GOM that are west of 87 degrees, 30 minutes West longitude, and in the planning areas offshore Alaska.
(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.
(d) Under 42 U.S.C. 15904-15905, we may suspend royalties for designated volumes of gas production from deep and ultra-deep wells on a lease if:
(1) Your lease is in shallow water (water less than 400 meters deep) and you produce from an ultra-deep well (top of the perforated interval is at least 20,000 feet TVD SS) or your lease is in waters entirely more than 200 meters and entirely less than 400 meters deep and you produce from a deep well (top of the perforated interval is at least 15,000 feet TVD SS);
(2) Your lease is in the designated area of the GOM (wholly west of 87 degrees, 30 minutes west longitude); and
(3) Your lease is not eligible for deep water royalty relief.
We may reduce or suspend royalties for Outer Continental Shelf (OCS) leases or projects that meet the criteria in the following table.
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. 104-134, 110 Stat. 1321, April 26, 1996) authorize us to collect these fees.
(a) We will specify the necessary fees for each of the types of royalty relief applications and possible MMS audits in a Notice to Lessees. We will periodically update the fees to reflect changes in costs, as well as provide other information necessary to administer royalty relief.
(b) You must file all payments electronically through the
The tables in this section summarize the similar application and approval provisions for the discretionary end-of-life and deep water royalty relief programs in §§ 203.50 to 203.91. Because royalty relief for deep gas on leases not subject to deep water royalty relief, as provided for under §§ 203.40 to 203.48, does not involve an application, its provisions do not parallel the other two royalty relief programs and are not summarized in this section.
(a) We require the information elements indicated by an X in the following table and described in §§ 203.51, 203.62, and 203.81 through 203.89 for applications for royalty relief.
(b) We require the confirmation elements indicated by an X in the following table and described in §§ 203.70, 203.81 and 203.90 through 203.91 to retain royalty relief.
(c) The following table indicates by an X, and §§ 203.50, 203.52, 203.60 and 203.67 describe, the prerequisites for our approval of your royalty relief application.
(d) The following table indicates by an X, and §§ 203.52 and 203.74 through 203.75 describe, the prerequisites for a redetermination of our royalty relief decision.
(e) The following table indicates by an X, and §§ 203.53 and 203.69 describe, the characteristics of approved royalty relief.
(f) The following table indicates by an X, and §§ 203.54 and 203.78 describe, circumstances under which we discontinue your royalty relief.
(g) The following table indicates by an X, and §§ 203.55 and 203.76 through 203.77 describe, circumstances under which we end or reduce royalty relief.
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501
(b) The MMS collects this information to make decisions on the economic viability of leases requesting a suspension or elimination of royalty or net profit share. Responses are required to obtain a benefit or are mandatory according to 43 U.S.C. 1331
(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 5438, 1849 C Street, NW., Washington, DC 20240.
Your lease may receive a royalty suspension volume (RSV) under §§ 203.31 through 203.36 if the lease meets all the requirements of this section.
(a) The lease is located in the GOM wholly west of 87 degrees, 30 minutes West longitude in water depths entirely less than 400 meters deep.
(b) The lease has not produced gas or oil from a deep well or an ultra-deep well, except as provided in § 203.31(b).
(c) If the lease is located entirely in more than 200 meters and entirely less than 400 meters of water, it must either:
(1) Have been issued before November 28, 1995, and not been granted deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by section 302 of the Deep Water Royalty Relief Act; or
(2) Have been issued after November 28, 2000, and not been granted deep water royalty relief under §§ 203.60 through 203.79.
(a) Subject to the administrative requirements of § 203.35 and the price conditions in § 203.36, your qualified well earns your lease an RSV shown in the following table in billions of cubic feet (BCF) or in thousands of cubic feet (MCF) as prescribed in § 203.33:
(b)(1) This paragraph applies if your lease:
(i) Has produced gas or oil from a deep well with a perforated interval the top of which is less than 18,000 feet TVD SS;
(ii) Was issued in a lease sale held between January 1, 2004, and December 31, 2005; and
(iii) The terms of your lease expressly incorporate the provisions of §§ 203.41 through 203.47 as they existed at the time the lease was issued.
(2) Subject to the administrative requirements of § 203.35 and the price conditions in § 203.36, your qualified well earns your lease an RSV shown in the following table in BCF or MCF as prescribed in § 203.33:
(c) Lessees may request a refund of or recoup royalties paid on production from qualified phase 2 or phase 3 ultra-deep wells that:
(1) Occurs before December 18, 2008 and
(2) Is subject to application of an RSV under either § 203.31 or § 203.41.
(d) The following examples illustrate how this section applies. These examples assume that your lease is located in the GOM west of 87 degrees, 30 minutes West longitude and in water less than 400 meters deep (see § 203.30(a)), has no existing deep or ultra-deep wells and that the price thresholds prescribed in § 203.36 have not been exceeded.
In 2008, you drill and begin producing from an ultra-deep well with a perforated interval the top of which is 25,000 feet TVD SS, and your lease has had no prior production from a deep or ultra-deep well. Assuming your lease has no deepwater royalty relief (see § 203.30(c)), your lease is eligible (according to § 203.30(b)) to earn an RSV under § 203.31 because it has not yet produced from a deep well. Your lease earns an RSV of 35 BCF under this section when this well begins producing. According to § 203.31(a), your 25,000 foot well qualifies your lease for this RSV because the well was drilled after the relief authorized here became effective (when the proposed version of this rule was published on May 18, 2007) and produced from an interval that meets the criteria for an ultra-deep well (
In 2005, you spudded and began producing from an ultra-deep well with a perforated interval the top of which is 23,000 feet TVD SS. Your lease earns no RSV under this section from this phase 1 ultra-deep well (as defined in § 203.0) because you spudded the well before the publication date (May 18, 2007) of the proposed rule when royalty relief under § 203.31(a) became effective. However, this ultra-deep well may earn an RSV of 25 BCF for your lease under § 203.41 (that became effective May 3, 2004), if the lease is located in water depths partly or entirely less than 200 meters and has not previously produced from a deep well (§ 203.30(b)).
In 2000, you began producing from a deep well with a perforated interval the top of which is 16,000 feet TVD SS and your lease is located in water 100 meters deep. Then in 2008, you drill and produce from a new ultra-deep well with a perforated interval the top of which is 24,000 feet TVD SS. Your lease earns no RSV under either this section or § 203.41 because the 16,000-foot well was drilled before we offered any way to earn an RSV for producing from a deep well (see dates in the definition of qualified well in § 203.0) and because the existence of the 16,000-foot well means the lease is not eligible (see § 203.30(b)) to earn an RSV for the 24,000-foot well. Because the lease existed in the year 2000, it cannot be eligible for the exception to this eligibility condition provided in § 203.31(b).
In 2008, you spud and produce from an ultra-deep well with a perforated interval the top of which is 22,000 feet TVD SS, your lease is located in water 300 meters deep, and your lease has had no previous production from a deep or ultra-deep well. Your lease earns an RSV of 35 BCF under this section when this well begins producing because your lease meets the conditions in § 203.30 and the well fits the definition of a phase 2 ultra-deep well (in § 203.0). Then in 2010, you spud and produce from a deep well with a perforated interval the top of which is 16,000 feet TVD SS. Your 16,000-foot well earns no RSV because it is on a lease that already has a producing well at least 18,000 feet subsea (see § 203.42(a)), but any remaining RSV earned by the ultra-deep well would also be applied to production from the deep well as prescribed in § 203.33(a)(2), or § 203.33(b)(2) if
In 2008, you spud a deep well with a perforated interval the top of which is 17,000 feet TVD SS that becomes a qualified well and earns an RSV of 15 BCF under § 203.41 when it begins producing. Then in 2011, you spud an ultra-deep well with a perforated interval the top of which is 26,000 feet TVD SS. Your 26,000-foot well becomes a qualified ultra-deep well because it meets the date and depth conditions in this definition under § 203.0 when it begins producing, but your lease earns no additional RSV under this section or § 203.41 because it is on a lease that already has production from a deep well (see § 203.30(b)). Both the qualified deep well and the qualified ultra-deep well would share your lease's total RSV of 15 BCF in the manner prescribed in §§ 203.33 and 203.43.
In 2008, you spud a qualified ultra-deep well that is a sidetrack with a sidetrack measured depth of 21,000 feet and a perforated interval the top of which is 25,000 feet TVD SS. This well meets the definition of an ultra-deep well but is too long to be classified an ultra-deep short sidetrack in § 203.0. If your lease is located in 150 meters of water and has not previously produced from a deep well, your lease earns an RSV of 35 BCF because it was drilled after the effective date for earning this RSV. Further, this RSV applies to gas production from this and any future qualified deep and qualified ultra-deep wells on your lease, as prescribed in § 203.33. The absence of an expiration date for earning an RSV on an ultra-deep well means this long sidetrack well becomes a qualified well whenever it starts production. If your sidetrack has a sidetrack measured depth of 14,000 feet and begins production in March 2009, it earns an RSV of 12.4 BCF under this section because it meets the definitions of a phase 2 ultra-deep well (production begins before the expiration date for the pre-existing relief in its water depth category) and an ultra-deep short sidetrack in § 203.0. However, if it does not begin production until 2010, it earns no RSV because it is too short as a phase 3 ultra-deep well to be a qualified ultra-deep well.
Your lease was issued in June 2004 and expressly incorporates the provisions of §§ 203.41 through 203.47 as they existed at that time. In January 2005, you spud a deep well (well no. 1) with a perforated interval the top of which is 16,800 feet TVD SS that becomes a qualified well and earns an RSV of 15 BCF under § 203.41 when it begins producing. Then in February 2008, you spud an ultra-deep well (well no. 2) with a perforated interval the top of which is 22,300 feet that begins producing in November 2008, after well no. 1 has started production. Well no. 2 earns your lease an additional RSV of 10 BCF under paragraph (b) of this section because it begins production in time to be classified as a phase 2 ultra-deep well. If, on the other hand, well no. 2 had begun producing in June 2009, it would earn no additional RSV for the lease because it would be classified as a phase 3 ultra-deep well and thus is not entitled to the exception under paragraph (b) of this section.
(a) If a qualified ultra-deep well on your lease is within a unitized portion of your lease, the RSV earned by that well under this section applies only to your lease and not to other leases within the unit or to the unit as a whole.
(b) If your qualified ultra-deep well is a directional well (either an original well or a sidetrack) drilled across a lease line, then either:
(1) The lease with the perforated interval that initially produces earns the RSV or
(2) If the perforated interval crosses a lease line, the lease where the surface of the well is located earns the RSV.
(c) Any RSV earned under § 203.31 is in addition to any royalty suspension supplement (RSS) for your lease under § 203.45 that results from a different wellbore.
(d) If your lease earns an RSV under § 203.31 and later produces from a deep well that is not a qualified well, the RSV is not forfeited or terminated, but you may not apply the RSV earned under § 203.31 to production from the non-qualified well.
(e) You owe minimum royalties or rentals in accordance with your lease terms notwithstanding any RSVs allowed under paragraphs (a) and (b) of § 203.31.
(f) Unused RSVs transfer to a successor lessee and expire with the lease.
(a) You must apply the RSV allowed in § 203.31(a) and (b) to gas volumes produced from qualified wells on or after May 18, 2007, reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease under § 216.53. All gas production from qualified wells reported on the OGOR-A, including production not subject to royalty, counts toward the total lease RSV earned by both deep or ultra-deep wells on the lease.
(b) This paragraph applies to any lease with a qualified phase 2 or phase 3 ultra-deep well that is not within an MMS-approved unit. Subject to the price conditions of § 203.36, you must apply the RSV prescribed in § 203.31 as required under the following paragraphs (b)(1) and (b)(2) of this section.
(1) You must apply the RSV to the earliest gas production occurring on and after the later of May 18, 2007, or the date the first qualified phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production from qualified wells on your lease, regardless of their depth, for which you have met the requirements in § 203.35 or § 203.44.
(c) This paragraph applies to any lease with a qualified phase 2 or phase 3 ultra-deep well where all or part of the lease is within an MMS-approved unit. Under the unit agreement, a share of the production from all the qualified wells in the unit participating area would be allocated to your lease each month according to the participating area percentages. Subject to the price conditions of § 203.36, you must apply the RSV prescribed in § 203.31 as follows:
(1) You must apply the RSV to the earliest gas production occurring on and after the later of May 18, 2007, or the date that the first qualified phase 2 or phase 3 ultra-deep well that earns your lease the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production:
(i) From qualified wells on the non-unitized area of your lease, regardless of their depth, for which you have met the requirements in § 203.35 or § 203.44; and
(ii) Allocated to your lease under an MMS-approved unit agreement from qualified wells on unitized areas of your lease and on other leases in participating areas of the unit, regardless of their depth, for which the requirements in § 203.35 or § 203.44 have been met. The allocated share under paragraph (a)(2)(ii) of this section does not increase the RSV for your lease.
The east half of your lease A is unitized with all of lease B. There is one qualified phase 2 ultra-deep well on the non-unitized portion of lease A that earns lease A an RSV of 35 BCF under § 203.31, one qualified deep well on the unitized portion of lease A (drilled after the ultra-deep well on the non-unitized portion of that lease) and a qualified phase 2 ultra-deep well on lease B that earns lease B a 35 BCF RSV under § 203.31. The participating area percentages allocate 40 percent of production from both of the unit qualified wells to lease A and 60 percent to lease B. If the non-unitized qualified phase 2 ultra-deep well on lease A produces 12 BCF, and the unitized qualified well on lease A produces 18 BCF, and the qualified well on lease B produces 37 BCF, then the production volume from and allocated to lease A to which the lease A RSV applies is 34 BCF [12 + (18 + 37)(0.40)]. The production volume allocated to lease B to which the lease B RSV applies is 33 BCF [(18 + 37)(0.60)]. None of the volumes produced from a well that is not within a unit participating area may be allocated to other leases in the unit.
(d) You must begin paying royalties when the cumulative production of gas from all qualified wells on your lease, or allocated to your lease under paragraph (b) of this section, reaches the applicable RSV allowed under § 203.31 or § 203.41. For the month in which cumulative production reaches this RSV, you owe royalties on the portion of gas production from or allocated to your lease that exceeds the RSV remaining at the beginning of that month.
You may not apply an RSV earned under § 203.31:
(a) To production from completions less than 15,000 feet TVD SS, except in cases where the qualified well is re-perforated in the same reservoir previously perforated deeper than 15,000 feet TVD SS;
(b) To production from a deep well or ultra-deep well on any other lease, except as provided in paragraph (c) of § 203.33;
(c) To any liquid hydrocarbon (oil and condensate) volumes; or
(d) To production from a deep well or ultra-deep well that commenced drilling before:
(1) March 26, 2003, on a lease that is located entirely or partly in water less than 200 meters deep; or
(2) May 18, 2007, on a lease that is located entirely in water more than 200 meters deep.
To use an RSV earned under § 203.31:
(a) You must notify the MMS Regional Supervisor for Production and Development in writing of your intent to begin drilling operations on all your ultra-deep wells.
(b) Before beginning production, you must meet any production measurement requirements that the MMS Regional Supervisor for Production and Development has determined are necessary under 30 CFR part 250, subpart L.
(c)(1) Within 30 days of the beginning of production from any wells that would become qualified phase 2 or phase 3 ultra-deep wells by satisfying the requirements of this section:
(i) Provide written notification to the MMS Regional Supervisor for Production and Development that production has begun; and
(ii) Request confirmation of the size of the RSV earned by your lease.
(2) If you produced from a qualified phase 2 or phase 3 ultra-deep well before December 18, 2008, you must provide the information in paragraph (c)(1) of this section no later than January 20, 2009.
(d) If you cannot produce from a well that otherwise meets the criteria for a qualified phase 2 ultra-deep well that is an ultra-deep short sidetrack before May 3, 2009, on a lease that is located entirely or partly in water less than 200 meters deep, or before May 3, 2013, on a lease that is located entirely in water more than 200 meters but less than 400 meters deep, the MMS Regional Supervisor for Production and Development may extend the deadline for beginning production for up to 1 year, based on the circumstances of the particular well involved, if it meets all the following criteria.
(1) The delay occurred after drilling reached the total depth in your well.
(2) Production (other than test production) was expected to begin from the well before May 3, 2009, on a lease that is located entirely or partly in water less than 200 meters deep or before May 3, 2013, on a lease that is located entirely in water more than 200 meters but less than 400 meters deep. You must provide a credible activity schedule with supporting documentation.
(3) The delay in beginning production is for reasons beyond your control, such as adverse weather and accidents which MMS deems were unavoidable.
(a) You must pay royalties on all gas production to which an RSV otherwise would be applied under § 203.33 for any calendar year in which the average daily closing New York Mercantile Exchange (NYMEX) natural gas price exceeds the applicable threshold price shown in the following table.
(b) For purposes of paragraph (a) of this section, determine the threshold price for any calendar year after 2007 by:
(1) Determining the percentage of change during the year in the Department of Commerce's implicit price deflator for the gross domestic product; and
(2) Adjusting the threshold price for the previous year by that percentage.
(c) The following examples illustrate how this section applies.
Assume that a lessee drills and begins producing from a qualified phase 2 ultra-deep well in 2008 on a lease issued in 2004 in less than 200 meters of water that earns the lease an RSV of 35 BCF. Further, assume the well produces a total of 18 BCF by the end of 2009 and in both of those years, the average daily NYMEX closing natural gas price is less than $10.15 (adjusted for inflation after 2007). The lessee does not pay royalty on the 18 BCF because the gas price threshold under paragraph (a)(1) of this section applies to the first 25 BCF of this RSV earned by this phase 2 ultra-deep well. In 2010, the well produces another 13 BCF. In that year, the average daily closing NYMEX natural gas price is greater than $4.55 per MMBtu (adjusted for inflation after 2007), but less than $10.15 per MMBtu (adjusted for inflation after 2007). The first 7 BCF produced in 2010 will exhaust the first 25 BCF (that is subject to the $10.15 threshold) of the 35 BCF RSV that the well earned. The lessee must pay royalty on the remaining 6 BCF produced in 2010, because it is subject to the $4.55 per MMBtu threshold under paragraph (a)(2)(ii) of this section which was exceeded.
Assume that a lessee:
(1) Drills and produces from well no.1, a qualified deep well in 2008 to a depth of 15,500 feet TVD SS that earns a 15 BCF RSV for the lease under § 203.41, which would be subject to a price threshold of $10.15 per MMBtu (adjusted for inflation after 2007), meaning the lease is partly or entirely in less than 200 meters of water;
(2) Later in 2008 drills and produces from well no. 2, a second qualified deep well to a depth of 17,000 feet TVD SS that earns no additional RSV (see § 203.41(c)(1)); and
(3) In 2015, drills and produces from well no. 3, a qualified phase 3 ultra-deep well that earns no additional RSV since the lease already has an RSV established by prior deep well production. Further assume that in 2015, the average daily closing NYMEX natural gas price exceeds $4.55 per MMBtu (adjusted for inflation after 2007) but does not exceed $10.15 per MMBtu (adjusted for inflation after 2007). In 2015, any remaining RSV earned by well no. 1 (which would have been applied to production from well nos. 1 and 2 in the intervening years), would be applied to production from all three qualified wells. Because the price threshold applicable to that RSV was not exceeded, the production from all three qualified wells would be royalty-free until the 15 BCF RSV earned by well no. 1 is exhausted.
Assume the same initial facts regarding the three wells as in Example 2. Further assume that well no. 1 stopped producing in 2011 after it had produced 8 BCF, and that well no. 2 stopped producing in 2012 after it had produced 5 BCF. Two BCF of the RSV earned by well no. 1 remain. That RSV would be applied to production from well no. 3 until it is exhausted, and the lessee therefore would not pay royalty on those 2 BCF produced in 2015, because the $10.15 per MMBtu (adjusted for inflation after 2007) price threshold is not exceeded. The determination of which price threshold applies to deep gas production depends on when the first qualified well earned the RSV for the lease, not on which wells use the RSV.
Assume that in February 2010 a lessee completes and begins producing from an ultra-deep well (at a depth of 21,500 feet
(d) You must pay any royalty due under this section no later than March 31 of the year following the calendar year for which you owe royalty. If you do not pay by that date, you must pay late payment interest under § 218.54 from April 1 until the date of payment.
(e) Production volumes on which you must pay royalty under this section count as part of your RSV.
Your lease may receive an RSV under §§ 203.41 through 203.44, and may receive an RSS under §§ 203.45 through 203.47, if it meets all the requirements of this section.
(a) The lease is located in the GOM wholly west of 87 degrees, 30 minutes West longitude in water depths entirely less than 400 meters deep.
(b) The lease has not produced gas or oil from a well with a perforated interval the top of which is 18,000 feet TVD SS or deeper that commenced drilling either:
(1) Before March 26, 2003, on a lease that is located partly or entirely in water less than 200 meters deep; or
(2) Before May 18, 2007, on a lease that is located in water entirely more than 200 meters and entirely less than 400 meters deep.
(c) In the case of a lease located partly or entirely in water less than 200 meters deep, the lease was issued in a lease sale held either:
(1) Before January 1, 2001;
(2) On or after January 1, 2001, and before January 1, 2004, and, in cases where the original lease terms provided for an RSV for deep gas production, the lessee has exercised the option provided for in § 203.49; or
(3) On or after January 1, 2004, and the lease terms provide for royalty relief under §§ 203.41 through 203.47 of this part. (
(d) If the lease is located entirely in more than 200 meters and less than 400 meters of water, it must either:
(1) Have been issued before November 28, 1995, and not been granted deep water royalty relief under 43 U.S.C. 1337(a)(3)(C), added by section 302 of the Deep Water Royalty Relief Act; or
(2) Have been issued after November 28, 2000, and not been granted deep water royalty relief under §§ 203.60 through 203.79.
(a) To qualify for a suspension volume under paragraphs (b) or (c) of this section, your lease must meet the requirements in § 203.40 and the requirements in the following table.
(b) If your lease meets the requirements in paragraph (a)(1) of this section, it earns the RSV prescribed in the following table:
(c) If your lease meets the requirements in paragraph (a)(2) of this section, it earns the RSV prescribed in the following table. The RSV specified in this paragraph is in addition to any RSV your lease already may have earned from a qualified deep well with a perforated interval whose top is from 15,000 feet to less than 18,000 feet TVD SS.
(d) Lessees may request a refund of or recoup royalties paid on production from qualified wells on a lease that is located in water entirely deeper than 200 meters but entirely less than 400 meters deep that:
(1) Occurs before December 18, 2008; and
(2) Is subject to application of an RSV under either § 203.31 or § 203.41.
(e) The following examples illustrate how this section applies, assuming your lease meets the location, prior production, and lease issuance conditions in § 203.40 and paragraph (a) of this section:
If you have a qualified deep well that is an original well with a perforated interval the top of which is 16,000 feet TVD SS, your lease earns an RSV of 15 BCF under paragraph (b)(1) of this section. This RSV must be applied to gas production from all qualified wells on your lease, as prescribed in §§ 203.43 and 203.48. However, if the top of the perforated interval is 18,500 feet TVD SS, the RSV is 25 BCF according to paragraph (b)(3) of this section.
If you have a qualified deep well that is a sidetrack, with a perforated interval the top of which is 16,000 feet TVD SS and a sidetrack measured depth of 6,789 feet, we round the measured depth to 6,800 feet and your lease earns an RSV of 8.08 BCF under paragraph (b)(2) of this section. This RSV would be applied to gas production from all qualified wells on your lease, as prescribed in §§ 203.43 and 203.48.
If you have a qualified deep well that is a sidetrack, with a perforated interval the top of which is 16,000 feet TVD SS and a sidetrack measured depth of 19,500 feet, your lease earns an RSV of 15 BCF. This RSV would be applied to gas production from all qualified wells on your lease, as prescribed in §§ 203.43 and 203.48, even though 4 BCF plus 600 MCF per foot of sidetrack measured depth equals 15.7 BCF because paragraph
If you have drilled and produced a deep well with a perforated interval the top of which is 16,000 feet TVD SS before March 26, 2003 (and the well therefore is not a qualified well and has earned no RSV under this section), and later drill:
(i) A deep well with a perforated interval the top of which is 17,000 feet TVD SS, your lease earns no RSV (see paragraph (c)(1) of this section);
(ii) A qualified deep well that is an original well with a perforated interval the top of which is 19,000 feet TVD SS, your lease earns an RSV of 10 BCF under paragraph (c)(2) of this section. This RSV would be applied to gas production from qualified wells on your lease, as prescribed in §§ 203.43 and 203.48; or
(iii) A qualified deep well that is a sidetrack with a perforated interval the top of which is 19,000 feet TVD SS, that has a sidetrack measured depth of 7,000 feet, your lease earns an RSV of 8.2 BCF under paragraph (c)(3) of this section. This RSV would be applied to gas production from qualified wells on your lease, as prescribed in §§ 203.43 and 203.48.
If you have a qualified deep well that is an original well with a perforated interval the top of which is 16,000 feet TVD SS, and later drill a second qualified well that is an original well with a perforated interval the top of which is 19,000 feet TVD SS, we increase the total RSV for your lease from 15 BCF to 25 BCF under paragraph (c)(2) of this section. We will apply that RSV to gas production from all qualified wells on your lease, as prescribed in §§ 203.43 and 203.48. If the second well has a perforated interval the top of which is 22,000 feet TVD SS (instead of 19,000 feet), the total RSV for your lease would increase to 25 BCF only in 2 situations: (1) If the second well was a phase 1 ultra-deep well,
If you have a qualified deep well that is a sidetrack, with a perforated interval the top of which is 16,000 feet TVD SS and a sidetrack measured depth of 4,000 feet, and later drill a second qualified well that is a sidetrack, with a perforated interval the top of which is 19,000 feet TVD SS and a sidetrack measured depth of 8,000 feet, we increase the total RSV for your lease from 6.4 BCF [4 + (600 * 4,000)/1,000,000] to 15.2 BCF {6.4 + [4 + (600 * 8,000)/1,000,000)]} under paragraphs (b)(2) and (c)(3) of this section. We would apply that RSV to gas production from all qualified wells on your lease, as prescribed in §§ 203.43 and 203.48. The difference of 8.8 BCF represents the RSV earned by the second sidetrack that has a perforated interval the top of which is deeper than 18,000 feet TVD SS.
The conditions and limitations in the following table apply to royalty relief under § 203.41.
If your first qualified deep well is a sidetrack with a perforated interval whose top is 16,000 feet TVD SS and earns an RSV of 12.5 BCF, and you later drill a qualified original deep well to 17,000 feet TVD SS, the RSV for your lease remains at 12.5 BCF and does not increase to 15 BCF. However, under paragraph (c) of § 203.41, if you subsequently drill a qualified deep well to a depth of 18,000 feet or greater TVD SS, you may earn an additional RSV.
(a) You must apply the RSV prescribed in § 203.41(b) and (c) to gas volumes produced from qualified wells on or after May 3, 2004, reported on the OGOR-A for your lease under § 216.53, as and to the extent prescribed in §§ 203.43 and 203.48.
(1) Except as provided in paragraph (a)(2) of this section, all gas production from qualified wells reported on the OGOR-A, including production that is not subject to royalty, counts toward the lease RSV.
(2) Production to which an RSS applies under §§ 203.45 and 203.46 does not count toward the lease RSV.
(b) This paragraph applies to any lease with a qualified deep well or qualified phase 1 ultra-deep well when no part of the lease is within an MMS-approved unit. Subject to the price conditions in § 203.48, you must apply the RSV prescribed in § 203.41 as required under the following paragraphs (b)(1) and (b)(2) of this section.
(1) You must apply the RSV to the earliest gas production occurring on and after the later of:
(i) May 3, 2004, for an RSV earned by a qualified deep well or qualified phase 1 ultra-deep well on a lease that is located entirely or partly in water less than 200 meters deep;
(ii) May 18, 2007, for an RSV earned by a qualified deep well on a lease that is located entirely in water more than 200 meters deep; or
(iii) The date that the first qualified well that earns your lease the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production from qualified wells on your lease, regardless of their depth, for which you have met the requirements in § 203.35 or § 203.44.
On a lease in water less than 200 meters deep, you began drilling an original deep well with a perforated interval the top of which is 18,200 feet TVD SS in September 2003, that became a qualified deep well in July 2004, when it began producing and using the RSV that it earned. You subsequently drill another original deep well with a perforated interval the top of which is 16,600 feet TVD SS, which becomes a qualified deep well when production begins in August 2008. The first well earned an RSV of 25 BCF (see § 203.41(a)(1) and (b)(3)). You must apply any remaining RSV each month beginning in August 2008 to production from both wells until the 25 BCF RSV is fully utilized according to paragraph (b)(2) of this section. If the second well had begun production in August 2009, it would not be a qualified deep well because it started production after expiration in May 2009 of the ability to qualify for royalty relief in this water depth, and could not share any of the remaining RSV (see definition of a qualified deep well in § 203.0).
On a lease in water between 200 and 400 meters deep, you begin drilling an original deep well with a perforated interval the top of which is 17,100 feet TVD SS in November 2010 that becomes a qualified deep well in June 2011 when it begins producing and using the RSV. You subsequently drill another original deep well with a perforated interval the top of which is 15,300 feet TVD SS which becomes a qualified deep well by beginning production in October 2011 (see definition of a qualified deep well in § 203.0). Only the first well earns an RSV equal to 15 BCF (
(c) This paragraph applies to any lease with a qualified deep well or qualified phase 1 ultra-deep well when all or part of the lease is within an MMS-approved unit. Under the unit
(1) You must apply the RSV to the earliest gas production occurring on and after the later of:
(i) May 3, 2004, for an RSV earned by a qualified well or qualified phase 1 ultra-deep well on a lease that is located entirely or partly in water less than 200 meters deep;
(ii) May 18, 2007, for an RSV earned by a qualified deep well on a lease that is located entirely in water more than 200 meters deep; or
(iii) The date that the first qualified well that earns your lease the RSV begins production (other than test production).
(2) You must apply the RSV to only gas production:
(i) From all qualified wells on the non-unitized area of your lease, regardless of their depth, for which you have met the requirements in § 203.35 or § 203.44; and,
(ii) Allocated to your lease under an MMS-approved unit agreement from qualified wells on unitized areas of your lease and on unitized areas of other leases in the unit, regardless of their depth, for which the requirements in § 203.35 or § 203.44 have been met.
(3) The allocated share under paragraph (c)(2)(ii) of this section does not increase the RSV for your lease. None of the volumes produced from a well that is not within a unit participating area may be allocated to other leases in the unit.
The east half of your lease A is unitized with all of lease B. There is one qualified 19,000-foot TVD SS deep well on the non-unitized portion of lease A, one qualified 18,500-foot TVD SS deep well on the unitized portion of lease A, and a qualified 19,400-foot TVD SS deep well on lease B. The participating area percentages allocate 32 percent of production from both of the unit qualified deep wells to lease A and 68 percent to lease B. If the non-unitized qualified deep well on lease A produces 12 BCF and the unitized qualified deep well on lease A produces 15 BCF, and the qualified deep well on lease B produces 10 BCF, then the production volume from and allocated to lease A to which the lease an RSV applies is 20 BCF [12 + (15 + 10) * (0.32)]. The production volume allocated to lease B to which the lease B RSV applies is 17 BCF [(15 + 10) * (0.68)].
(d) You must begin paying royalties when the cumulative production of gas from all qualified wells on your lease, or allocated to your lease under paragraph (c) of this section, reaches the applicable RSV allowed under § 203.31 or § 203.41. For the month in which cumulative production reaches this RSV, you owe royalties on the portion of gas production that exceeds the RSV remaining at the beginning of that month.
(e) You may not apply the RSV allowed under § 203.41 to:
(1) Production from completions less than 15,000 feet TVD SS, except in cases where the qualified deep well is re-perforated in the same reservoir previously perforated deeper than 15,000 feet TVD SS;
(2) Production from a deep well or phase 1 ultra-deep well on any other lease, except as provided in paragraph (c) of this section;
(3) Any liquid hydrocarbon (oil and condensate) volumes; or
(4) Production from a deep well or phase 1 ultra-deep well that commenced drilling before:
(i) March 26, 2003, on a lease that is located entirely or partly in water less than 200 meters deep, or
(ii) May 18, 2007, on a lease that is located entirely in water more than 200 meters deep.
(a) You must notify the MMS Regional Supervisor for Production and Development in writing of your intent to begin drilling operations on all deep wells and phase 1 ultra-deep wells; and
(b) Within 30 days of the beginning of production from all wells that would become qualified wells by satisfying the requirements of this section, you must:
(1) Provide written notification to the MMS Regional Supervisor for Production and Development that production has begun; and
(2) Request confirmation of the size of the royalty suspension volume earned by your lease.
(c) Before beginning production, you must meet any production measurement requirements that the MMS Regional Supervisor for Production and Development has determined are necessary under 30 CFR part 250, subpart L.
(d) You must provide the information in paragraph (b) of this section by January 20, 2009 if you produced before December 18, 2008 from a qualified deep well or qualified phase 1 ultra-deep well on a lease that is located entirely in water more than 200 meters and less than 400 meters deep.
(e) The MMS Regional Supervisor for Production and Development may extend the deadline for beginning production for up to one year for a well that cannot begin production before the applicable date prescribed in the definition of “qualified deep well” in § 203.0 if it meets all of the following criteria.
(1) The well otherwise meets the criteria in the definition of a qualified deep well in § 203.0.
(2) The delay in production occurred after reaching total depth in the well.
(3) Production (other than test production) was expected to begin from the well before the applicable deadline in the definition of a qualified deep well in § 203.0. You must provide a credible activity schedule with supporting documentation.
(4) The delay in beginning production is for reasons beyond your control, such as adverse weather and accidents which MMS deems were unavoidable.
Your lease may earn a royalty suspension supplement. Subject to paragraph (d) of this section, the royalty suspension supplement is in addition to any royalty suspension volume your lease may earn under § 203.41.
(a) If you drill a certified unsuccessful well and you satisfy the administrative requirements of § 203.47, subject to the price conditions in § 203.48, your lease earns an RSS shown in the following table. The RSS is shown in billions of cubic feet of gas equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE) and is applicable to oil and gas production as prescribed in § 204.46.
(b) This paragraph applies to oil and gas volumes you report on the OGOR-A for your lease under § 216.53.
(1) You must apply the RSS prescribed in paragraph (a) of this section, in accordance with the requirements in § 203.46, to all oil and gas produced from the lease:
(i) On or after December 18, 2008, if your lease is located in water more than 200 meters but less than 400 meters deep; or
(ii) On or after May 3, 2004, if your lease is located in water partly or entirely less than 200 meters deep.
(2) Production to which an RSV applies under §§ 203.31 through 203.33 and §§ 203.41 through 203.43 does not count toward the lease RSS. All other production, including production that is
If you drill a certified unsuccessful well that is an original well to a target 19,000 feet TVD SS, your lease earns an RSS of 5 BCFE that would be applied to gas and oil production if your lease has not previously produced from a deep well or an ultra-deep well, or you earn an RSS of 2 BCFE of gas and oil production if your lease has previously produced from a deep well with a perforated interval from 15,000 to less than 18,000 feet TVD SS, as prescribed in § 203.46.
If you drill a certified unsuccessful well that is a sidetrack that reaches a target 19,000 feet TVD SS, that has a sidetrack measured depth of 12,545 feet, and your lease has not produced gas or oil from any deep well or ultra-deep well, MMS rounds the sidetrack measured depth to 12,500 feet and your lease earns an RSS of 2.3 BCFE of gas and oil production as prescribed in § 203.45.
(c) The conversion from oil to gas for using the royalty suspension supplement is specified in § 203.73.
(d) Each lease is eligible for up to two royalty suspension supplements. Therefore, the total royalty suspension supplement for a lease cannot exceed 10 BCFE.
(1) You may not earn more than one royalty suspension supplement from a single wellbore.
(2) If you begin drilling a certified unsuccessful well on one lease but the completion target is on a second lease, the entire royalty suspension supplement belongs to the second lease. However, if the target straddles a lease line, the lease where the surface of the well is located earns the royalty suspension supplement.
(e) If the same wellbore that earns an RSS as a certified unsuccessful well later produces from a perforated interval the top of which is 15,000 feet TVD or deeper and becomes a qualified well, it will be subject to the following conditions:
(1) Beginning on the date production starts, you must stop applying the royalty suspension supplement earned by that wellbore to your lease production.
(2) If the completion of this qualified well is on your lease or, in the case of a directional well, is on another lease, then you must subtract from the royalty suspension volume earned by that qualified well the royalty suspension supplement amounts earned by that wellbore that have already been applied either on your lease or any other lease. The difference represents the royalty suspension volume earned by the qualified well.
(f) If the same wellbore that earned a royalty suspension supplement later has a sidetrack drilled from that wellbore, you are not required to subtract any royalty suspension supplement earned by that wellbore from the royalty suspension volume that may be earned by the sidetrack.
(g) You owe minimum royalties or rentals in accordance with your lease terms notwithstanding any royalty suspension supplements under this section.
(a) Subject to the requirements of §§ 203.40, 203.43, 203.45, 203.47, and 203.48, you must apply an RSS in § 203.45 to the earliest oil and gas production:
(1) Occurring on and after the day you file the information under § 204.47(b),
(2) From, or allocated under an MMS-approved unit agreement to, the lease on which the certified unsuccessful well was drilled, without regard to the drilling depth of the well producing the gas or oil.
(b) If you have a royalty suspension volume for the lease under § 203.41, you must use the royalty suspension volumes for gas produced from qualified wells on the lease before using royalty suspension supplements for gas produced from qualified wells.
You have two shallow oil wells on your lease. Then you drill a certified unsuccessful well and earn a royalty suspension supplement of 5 BCFE. Thereafter, you begin production from an original well that is a qualified well that earns a royalty suspension volume of 15 BCF. You use only 2 BCFE of the royalty suspension supplement before the oil wells deplete. You must use up the 15 BCF of royalty suspension volume before you use the remaining
(c) If you have no current production on which to apply the RSS allowed under § 203.45, your RSS applies to the earliest subsequent production of gas and oil from, or allocated under an MMS-approved unit agreement to, your lease.
(d) Unused royalty suspension supplements transfer to a successor lessee and expire with the lease.
(e) You may not apply the RSS allowed under § 203.45 to production from any other lease, except for production allocated to your lease from an MMS-approved unit agreement. If your certified unsuccessful well is on a lease subject to an MMS-approved unit agreement, the lessees of other leases in the unit may not apply any portion of the RSS for your lease to production from the other leases in the unit.
(f) You must begin or resume paying royalties when cumulative gas and oil production from, or allocated under an MMS-approved unit agreement to, your lease (excluding any gas produced from qualified wells subject to a royalty suspension volume allowed under § 203.41) reaches the applicable royalty suspension supplement. For the month in which the cumulative production reaches this royalty suspension supplement, you owe royalties on the portion of gas or oil production that exceeds the amount of the royalty suspension supplement remaining at the beginning of that month.
(a) Before you start drilling a well on your lease targeted to a reservoir at least 18,000 feet TVD SS, you must notify, in writing, the MMS Regional Supervisor for Production and Development of your intent to begin drilling operations and the depth of the target.
(b) After drilling the well, you must provide the MMS Regional Supervisor for Production and Development within 60 days after reaching the total depth in your well:
(1) Information that allows MMS to confirm that you drilled a certified unsuccessful well as defined under § 203.0, including:
(i) Well log data, if your original well or sidetrack does not meet the producibility requirements of 30 CFR part 250, subpart A; or
(ii) Well log, well test, seismic, and economic data, if your well does meet the producibility requirements of 30 CFR part 250, subpart A; and
(2) Information that allows MMS to confirm the size of the royalty suspension supplement for a sidetrack, including sidetrack measured depth and supporting documentation.
(c) If you commenced drilling a well that otherwise meets the criteria for a certified unsuccessful well on a lease located entirely in more than 200 meters and entirely less than 400 meters of water on or after May 18, 2007, and finished it before December 18, 2008, you must provide the information in paragraph (b) of this section no later than February 17, 2009.
(a) You must pay royalties on all gas and oil production for which an RSV or an RSS otherwise would be allowed under §§ 203.40 through 203.47 for any calendar year when the average daily closing NYMEX natural gas price exceeds the applicable threshold price shown in the following table.
(b) Determine the threshold price for any calendar year after 2007 by adjusting the threshold price in the previous year by the percentage that the implicit price deflator for the gross domestic product, as published by the Department of Commerce, changed during the calendar year.
(c) You must pay any royalty due under this section no later than March 31 of the year following the calendar year for which you owe royalty. If you do not pay by that date, you must pay late payment interest under § 218.54 from April 1 until the date of payment.
(d) Production volumes on which you must pay royalty under this section count as part of your RSV and RSS.
(a) You may exercise an option to replace the applicable lease terms for royalty relief related to deep-well drilling with those in § 203.0 and §§ 203.40 through 203.48 if you have a lease issued with royalty relief provisions for deep-well drilling. Such leases:
(1) Must be issued as part of an OCS lease sale held after January 1, 2001, and before April 1, 2004; and
(2) Must be located wholly west of 87 degrees, 30 minutes West longitude in the GOM entirely or partly in water less than 200 meters deep.
(b) To exercise the option under paragraph (a) of this section, you must notify, in writing, the MMS Regional Supervisor for Production and Development of your decision before September 1, 2004 or 180 days after your lease is issued, whichever is later, and specify the lease and block number.
(c) Once you exercise the option under paragraph (a) of this section, you are subject to all the activity, timing, and administrative requirements pertaining to deep gas royalty relief as specified in §§ 203.40 through 203.48.
(d) Exercising the option under paragraph (a) of this section is irrevocable. If you do not exercise this option, then the terms of your lease apply.
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., begin re-injecting rather than recovering gas) during the qualifying months, or if you do so while we are processing your application, we may defer action on your application until you revise it to show the new circumstances.
(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
(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 return to the effective rate in the first full month following this termination.
(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.
You may apply for royalty relief under §§ 203.61(b) and 203.62 for an individual lease, unit or project if you:
(a) Hold a pre-Act lease (as defined in § 203.0) that we have assigned to an authorized field (as defined in § 203.0);
(b) Propose an expansion project (as defined in § 203.0); or
(c) Propose a development 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.
(a) You must send a complete application and the required fee to the MMS Regional Director for your region.
(b) Your application for royalty relief offshore Alaska or in deep water in the GOM must include an original and two copies (one set of digital information) of:
(1) Administrative information report;
(2) Economic Viability and relief justification report;
(3) G&G report;
(4) Engineering report;
(5) Production report; and
(6) Cost report.
(c) Section 203.82 explains why we are authorized to require these reports.
(d) Sections 203.81, 203.83, and 203.85 through 203.89 describe what these reports must include. The MMS regional office for your region will guide you on the format for the required reports, and we encourage you to contact this office before preparing your application for this guidance.
(a) 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 (a)(3) of this section and § 203.64. However, we will evaluate all acreage that may eventually become part of the authorized field. Therefore, if you have any other leases that you believe may eventually be part of the authorized field, you must submit data for these leases according to § 203.81.
(1) The Regional Director maintains a Field Names Master List with updates of all leases in each designated field.
(2) 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 the field. We will not disclose proprietary data when explaining our assumptions and reasons for our determinations under § 203.67.
(3) 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
(b) If your application seeks only relief for a development project or an expansion project, your application does not have to include all leases in the field.
You may file one complete application for royalty relief during the life of the field or for a development project or an expansion project designed to produce a reservoir or set of reservoirs. 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, evaluate your first application on a development project or an expansion project within 150 days and evaluate a redetermination under § 203.75 within 120 days after we determine that 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 under § 203.65, you get royalty relief according to the following table.
We will not approve applications if we determine that royalty relief cannot make the field, development project, or expansion project economically viable. Your field or project must be uneconomic while you are paying royalties and must become economic with royalty relief.
(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 according to the following table.
If we approve your application, subject to certain conditions, we will not collect royalties on a specified suspension volume for your field, development project, or expansion project. Suspension volumes include volumes allocated to a lease under an approved unit agreement, but exclude any volumes of production that are not normally royalty-bearing under the lease or the regulations of this chapter (e.g., fuel gas).
(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) For development projects, any relief we grant applies only to project wells and replaces the royalty relief, if any, with which we issued your lease.
(c) If your project is economic given the royalty relief with which we issued your lease, we will reject the application.
(d) If the lease has earned or may earn deep gas royalty relief under §§ 203.40 through 203.49 or ultra-deep gas royalty relief under §§ 203.30 through 203.36, we will take the deep gas royalty relief or ultra-deep gas royalty relief into account in determining whether further royalty relief for a development project is necessary for production to be economic.
(e) If neither paragraph (c) nor (d) of this section apply, the
(f) If your application includes pre-Act leases in different categories of water depth, we apply the minimum royalty suspension volume for the deepest such lease then assigned to the field. We base the water depth and makeup of a field on the water-depth delineations in the “Lease Terms and Economic Conditions” map and the “Fields Directory” documents and updates in effect at the time your application is deemed complete. These publications are available from the MMS Gulf of Mexico Regional Office.
(g) You will get a royalty suspension volume above the minimum if we determine that you need more to make the field or development project economic.
(h) For expansion projects, the minimum royalty suspension volume equals 10 percent of the median of the distribution of known recoverable resources upon which we based approval of your application from all reservoirs included in your project plus any suspension volumes required under § 203.66. If we determine that your expansion project may be economic only with more relief, we will determine and grant you the royalty suspension volume necessary to make the project economic.
(i) The royalty suspension volume applicable to specific leases will continue through the end of the month in which cumulative production reaches that volume. You must calculate cumulative production from all the leases in the authorized field or 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, 203.90, and 203.91 describe what these reports must include. The MMS Regional Office for your region will prescribe the formats.
The allocation depends on when production occurs, when we issued the lease, when we assigned it to the field, and whether we award the volume suspension by an approved application or establish it in the lease terms, as prescribed in this section.
(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 leases in the field that participate in the application until their cumulative production equals the approved volume. The following conditions also apply:
(b) When a project has more than one lease, the royalty suspension volume for each lease equals that lease's actual production from the project (or production allocated under an approved unit agreement) until total production for all leases in the project equals the project's approved royalty suspension volume.
(c) 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-suspension volume, even if we have already granted a royalty-suspension volume to the field that encompasses the project. But the reserves associated with the project must not have been part of our original determination, and the project must meet the evaluation criteria of § 203.67.
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.
You may request a redetermination after we withdraw approval or after you renounce royalty relief, unless we withdraw approval due to your providing false or intentionally inaccurate information. Under certain conditions you may also request a redetermination if we deny your application or if you want your approved royalty suspension volume to change. In these instances, to be eligible for a redetermination, at least one of the following four 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) You demonstrate in your new application that the technology that most efficiently develops this field or lease was not considered or deemed feasible in the original application. Your newly proposed technology must improve the profitability, under equivalent market conditions, of the field or lease relative to the development system proposed in the prior application.
(c) Your current reference price decreases by more than 25 percent from your base reference price as calculated under this paragraph.
(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 light sweet crude oil and natural gas for the full 12 calendar months preceding the date of your most recently approved 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.
(d) 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 recently approved 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, or from 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 within18 months of the date we approved your application, unless the MMS Director grants you an extension under § 203.79(c). If you start building the proposed system and then suspend its construction before completion, and you do not restart continuous building of the proposed system within 18 months of our approval, we will withdraw the relief we granted.
(c) Your actual development costs are less than 80 percent of the eligible development costs estimated in your application's most likely scenario, and you do not report that fact in your post-production development report (§ 203.70). Development costs are those expenditures defined in § 203.89(b) incurred between the application submission date and start of production. If you report this fact in the post-production development report, you may retain the lesser of 50 percent of the original royalty suspension volume or 50 percent of the median of the distribution of the potentially recoverable resources anticipated in your application.
(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
Yes, you may voluntarily give up relief by sending a letter to that effect to the MMS Regional office for your region.
If prices rise above a base price threshold for light sweet crude oil or natural gas, you must pay full royalties on production otherwise subject to royalty relief approved by MMS under §§ 203.60-203.77 for your lease, unit or project as prescribed in this section.
(a) The following table shows the base price threshold for various types of leases, subject to paragraph (b) of this section. Note that, for post-November 2000 deepwater leases in the GOM, price thresholds apply on a lease basis, so different leases on the same development project or expansion project approved for royalty relief may have different price thresholds.
(b) An exception may occur if we determine that the price thresholds in paragraphs (a)(2) or (a)(3) mean the royalty suspension volume set under § 203.69 and in lease terms would provide inadequate encouragement to increase production or development, in which circumstance we could specify a different set of price thresholds on a case-by-case basis.
(c) Suppose your base oil price threshold set under paragraph (a) is $28.00 per barrel, and the daily closing NYMEX light sweet crude oil prices for the previous calendar year exceeds $28.00 per barrel, as adjusted in paragraph (h) of this section. In this case, we retract the royalty relief authorized in this subpart 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 March 31 of the current calendar year, and
(2) Pay royalties on all your oil production in the current year.
(d) Suppose your base gas price threshold set under paragraph (a) is $3.50 per million British thermal units (Btu), and the daily closing NYMEX light sweet crude oil prices for the previous calendar year exceeds $3.50 per million Btu, as adjusted in paragraph (h) of this section. In this case, we retract the royalty relief authorized in this subpart and you must:
(1) Pay royalties on all 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 March 31 of the current calendar year, and
(2) Pay royalties on all your gas production in the current year.
(e) Production under both paragraphs (c) and (d) of this section counts as part of the royalty-suspension volume.
(f) 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 prices for the current calendar year is $28.00 per barrel or less,
(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 (h) of this section.
(g) You must follow our regulations in part 230 of this chapter for receiving refunds or credits.
(h) We change the prices referred to in paragraphs (c), (d), and (f) of this section periodically. For pre-Act leases, these prices change during each calendar year after 1994 by the percentage that the implicit price deflator for the gross domestic product changed during the preceding calendar year. For post-November 2000 deepwater leases, these prices change as indicated in the lease instrument or in the Notice of Sale under which we issued the lease.
(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)
We may grant royalty relief when it serves the statutory purposes summarized in § 203.1 and our formal relief programs, including but not limited to the applicable levels of the royalty suspension volumes and price thresholds, provide inadequate encouragement to promote development or increase production. Unless your lease lies offshore of Alaska or wholly west of 87 degrees, 30 minutes West longitude in the GOM, your lease must be producing to qualify for relief. Before you may apply for royalty relief apart from our programs for end-of-life leases or for pre-Act deep water leases and development and expansion projects, we must agree that your lease or project has two or more of the following characteristics:
(a) The lease has produced for a substantial period and the lessee can recover significant additional resources. Significant additional resources means enough to allow production for at least a year more than would be profitable without royalty relief.
(b) Valuable facilities (e.g., a platform or pipeline that would be removed upon lease relinquishment) exist that we do not expect a successor lessee to use. If the facilities are located off the lease, their preservation must depend on continued production from the lease applying for royalty relief. We will only consider an allocable share of costs for off-lease facilities in the relief application.
(c) A substantial risk exists that no new lessee will recover the resources.
(d) The lessee made major efforts to reduce operating costs too recently to use the formal program for royalty relief (e.g., recent significant change in operations).
(e) Circumstances beyond the lessee's control, other than water depth, preclude reliance on one of the existing royalty relief programs.
(a) You must send us the supplemental reports, indicated in the following table by an X, that apply to your field. Sections 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 Regional office for your region.
(c) With your application and post-production development report, you must submit an additional report prepared by an independent 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 conform to our most recent guidelines on royalty relief. This means the data and information must—
(i) Include only eligible costs that are incurred during the qualification months; and
(ii) Be shown in the proper format.
(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 5438, 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) Well number, API number, location, and status 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 saturated (R
(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;
(7) Pressure-volume-temperature analysis, if available; and
(8) A table listing the wells and completions, and indicating which sands and fault blocks will be targeted for completion or recompletion.
(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) An explanation for excluding the reservoirs you are not planning to develop.
(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,
(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;
(7) A yield distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each gas reservoir; and
(8) Reserve or resource distribution by 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 (
(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 along with basic design specifications and drawings; 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 the conceptual basis for developing in phases and goals or milestones required for starting later phases.
(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)
(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)
(1) Operation;
(2) Equipment; and
(3) Existing royalty overrides (we will not use the royalty overrides in evaluations).
(d)
(1) Oil or gas tariffs from pipeline or tankerage;
(2) Trunkline and tieback lines; and
(3) Gas plant processing for natural gas liquids.
(e)
(f)
(g)
(h)
(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 Regional Director for your region 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. Also, you must have this report certified by an independent CPA according to § 203.81(c).
Section 104, Pub. L. 97-451, 96 Stat. 2451 (30 U.S.C. 1714), Pub. L. 109-432, Div C, Title I, 120 Stat. 3000.
(a) The Gulf of Mexico Energy Security Act of 2006 (GOMESA) directs the Secretary of the Interior to disburse a portion of the rentals, royalties, bonus, and other sums derived from certain Outer Continental Shelf (OCS) leases in the Gulf of Mexico (GOM) to the States of Alabama, Louisiana, Mississippi, and Texas (collectively identified as the Gulf producing States); to eligible coastal political subdivisions within those States; and to the Land and Water Conservation Fund. Shared GOMESA revenues are reserved for the following purposes:
(1) Projects and activities for the purposes of coastal protection, including conservation, coastal restoration, hurricane protection, and infrastructure directly affected by coastal wetland losses.
(2) Mitigation of damage to fish, wildlife, or natural resources.
(3) Implementation of a federally-approved marine, coastal, or comprehensive conservation management plan.
(4) Mitigation of the impact of OCS activities through the funding of onshore infrastructure projects.
(5) Planning assistance and administrative costs not-to-exceed 3 percent of the amounts received.
(b) This subpart sets forth the formula and methodology MMS will use to determine the amount of revenues to be disbursed and the amount to be allocated to each Gulf producing State and each eligible coastal political subdivision. For questions related to the revenue sharing provisions in this subpart, please contact: Chief, Financial Management, Minerals Revenue Management; P.O. Box 25165; Denver Federal Center, Building 85; MS-350B1; Denver, CO 80225-0165, or at (303) 231-3429.
Terms in this subpart have the following meaning:
(1) Located—
(i) South of the 181 Area;
(ii) West of the Military Mission Line; and
(iii) In the Central Planning Area;
(2) Excluded from the Proposed Final Outer Continental Shelf Oil and Gas Leasing Program for 1997-2002, dated August 1996, of the Minerals Management Service; and
(3) Included in the areas considered for oil and gas leasing, as identified in map 8, page 37, of the document entitled,
(1) Within the coastal zone (as defined in section 304 of the Coastal Zone Management Act of 1972 (16 U.S.C. 1453)) of the Gulf producing State as of December 20, 2006; and
(2) Not more than 200 nautical miles from the geographic center of any leased tract.
(1) The term qualified OCS revenues means, in the case of each of fiscal years 2007 through 2016, all rentals, royalties, bonus bids, and other sums received by the U.S. from leases entered into on or after December 20, 2006, located:
(i) In the 181 Area in the Eastern Planning Area; and
(ii) In the 181 South Area.
(iii) For applicable leased tracts intersected by the planning area administrative boundary line (e.g., separating the GOM Central Planning Area from the Eastern Planning Area), only the percent of revenues equivalent to the percent of surface acreage in the 181 Area in the Eastern Planning Area will be considered qualified OCS revenues.
(2) Exclusions to the term qualified OCS revenues include:
(i) Revenues from the forfeiture of a bond or other surety securing obligations other than royalties;
(ii) Civil penalties;
(iii) Royalties taken by the Secretary in-kind and not sold;
(iv) User fees; and
(v) Lease revenues explicitly circumscribed from GOMESA revenue sharing by statute or appropriations law.
For each of the fiscal years 2007 through 2016, 50 percent of the qualified OCS revenues will be placed in a special U.S. Treasury account from which 75 percent of the revenues will be disbursed to the Gulf producing States, and 25 percent will be disbursed to the Land and Water Conservation Fund. Each Gulf producing State will receive at least 10 percent of the qualified OCS revenues available for allocation to the Gulf producing States each fiscal year.
Of the revenues allocated to a Gulf producing State, 20 percent will be distributed to the coastal political subdivisions within that State.
(a) The MMS will determine the geographic centers of each applicable leased tract and, using the great circle distance method, will determine the closest distance from the geographic centers of each applicable leased tract to each Gulf producing State's coastline.
(b) Based on these distances, we will calculate the qualified OCS revenues to be disbursed to each Gulf producing State using the following procedure:
(1) For each Gulf producing State, we will calculate and total, over all applicable leased tracts, the mathematical inverses of the distances between the points on the State's coastline that are closest to the geographic centers of the applicable leased tracts and the geographic centers of the applicable leased tracts. For applicable leased tracts intersected by the planning area administrative boundary line, the geographic center used for the inverse distance determination will be the geographic center of the entire lease as if it were not intersected.
(2) For each Gulf producing State, we will divide the sum of each State's inverse distances, from all applicable leased tracts, by the sum of the inverse distances from all applicable leased tracts across all four Gulf producing States. We will multiply the result by the amount of qualified OCS revenues to be shared as shown below. In the formulas, I
(3) If in any fiscal year, this calculation results in less than a 10 percent allocation of the qualified OCS revenues to any Gulf producing State, we will recalculate the distribution. We will allocate 10 percent of the qualified OCS revenues to the State and recalculate the other States' shares of the remaining qualified OCS revenues omitting the State receiving the 10 percent minimum share and its 10 percent share from the calculation.
If bonus and royalty credits issued under Section 104(c) of the Gulf of Mexico Energy Security Act are used to pay bonuses or royalties on leases in the 181 Area located in the Eastern Planning Area and the 181 South Area, then there will be a corresponding reduction in qualified OCS revenues available for distribution.
The MMS will disburse funds to the coastal political subdivisions in accordance with the following criteria:
(a) Twenty-five percent of the qualified OCS revenues will be allocated to a Gulf producing State's coastal political subdivisions in the proportion that each coastal political subdivision's population bears to the population of all coastal political subdivisions in the producing State;
(b) Twenty-five percent of the qualified OCS revenues will be allocated to a Gulf producing State's coastal political subdivisions in the proportion that each coastal political subdivision's miles of coastline bears to the number of miles of coastline of all coastal political subdivisions in the producing State. Except that, for the State of Louisiana, proxy coastline lengths for coastal political subdivisions without a coastline will be considered to be
(c) Fifty percent of the revenues will be allocated to a Gulf producing State's coastal political subdivisions in amounts that are inversely proportional to the respective distances between the geographic center of each applicable leased tract and the point in each coastal political subdivision that is closest to the geographic center of each applicable leased tract. Except that, an applicable leased tract will be
If, during any fiscal year, there are no applicable leased tracts in the 181 Area in the Eastern Gulf of Mexico Planning Area, MMS will disburse funds to the coastal political subdivisions in accordance with the following criteria:
(a) Fifty percent of the revenues will be allocated to a Gulf producing State's coastal political subdivisions in the proportion that each coastal political subdivision's population bears to the population of all coastal political subdivisions in the State; and
(b) Fifty percent of the revenues will be allocated to a Gulf producing State's coastal political subdivisions in the proportion that each coastal political subdivision's miles of coastline bears to the number of miles of coastline of all coastal political subdivisions in the State. Except that, for the State of Louisiana, proxy coastline lengths for coastal political subdivisions without a coastline will be considered to be
(a) The MMS will disburse allocated funds in the fiscal year after MMS collects the qualified OCS revenues. For example, MMS will disburse funds in fiscal year 2010 from the qualified OCS revenues collected during fiscal year 2009.
(b) We intend to disburse funds on or before March 31st of the year following the fiscal year of qualified OCS revenues.
30 U.S.C. 1751; 31 U.S.C. 9701; 43 U.S.C. 1334.
Nomenclature changes to part 250 appear at 71 FR 46399 and 46400, Aug. 14, 2006.
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) Conduct to obtain data and information to ensure proper exploration or development of your lease or unit; and
(2) Can conduct without MMS approval of an application or permit.
(1) Geophysical and geological (G&G) surveys using magnetic, gravity, seismic reflection, seismic refraction, gas
(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, all installations permanently or temporarily attached to the seabed on the OCS (including manmade islands and bottom-sitting structures). They include mobile offshore drilling units (MODUs) or other vessels engaged in drilling or downhole operations, used for oil, gas or sulphur drilling, production, or related activities. They include all floating production systems (FPSs), variously described as column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc. They also include facilities for product measurement and royalty determination (e.g., lease Automatic Custody Transfer Units, gas meters) of OCS production on installations not on the OCS. Any group of OCS installations interconnected with walkways, or any group of installations that includes a central or primary installation with processing equipment and one or more satellite or secondary installations is a single facility. The Regional Supervisor may decide that the complexity of the individual installations justifies their classification as separate facilities.
(2) As used in § 250.303, means all installations or devices permanently or temporarily attached to the seabed. They include mobile offshore drilling units (MODUs), even while operating in the “tender assist” mode (
(3) As used in § 250.490(b), means a vessel, a structure, or an artificial island used for drilling, well completion, well-workover, or production operations.
(4) As used in §§ 250.900 through 250.921, means all installations or devices permanently or temporarily attached to the seabed. 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. They include all floating production systems (FPSs), including column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc. 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.
(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 and work areas 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) All cranes installed on fixed platforms must be operated in accordance with American Petroleum Institute's Recommended Practice for Operation and Maintenance of Offshore Cranes (API RP 2D), incorporated by reference as specified in 30 CFR 250.198.
(b) All cranes installed on fixed platforms must be equipped with a functional anti-two block device.
(c) If a fixed platform is installed after March 17, 2003, all cranes on the platform must meet the requirements of American Petroleum Institute Specification for Offshore Pedestal Mounted Cranes (API Spec 2C), incorporated by reference as specified in 30 CFR 250.198.
(d) All cranes manufactured after March 17, 2003, and installed on a fixed platform, must meet the requirements of API Spec 2C, incorporated by reference as specified in 30 CFR 250.198.
(e) You must maintain records specific to a crane or the operation of a crane installed on an OCS fixed platform, as follows:
(1) Retain all design and construction records, including installation records for any anti-two block safety devices, for the life of the crane. The records must be kept at the OCS fixed platform.
(2) Retain all inspection, testing, and maintenance records of cranes for at least 4 years. The records must be kept at the OCS fixed platform.
(3) Retain the qualification records of the crane operator and all rigger personnel for at least 4 years. The records must be kept at the OCS fixed platform.
(f) 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 Manager before you begin drilling or production activities on a lease. You may not begin welding until the District Manager 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 (
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 or a positive overbalance toward the formation.
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
(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 Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1, and Division 2 Locations (incorporated by reference as specified in § 250.198), or API RP 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1, and Zone 2 Locations (incorporated by reference as specified in § 250.198).
(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 Manager to witness each test that you conduct under this section; or
(2) Receive the District Manager'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 clean water-bearing sand—if mud conditions prevent a 20-negative millivolt reading beyond the shale baseline.
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.
(a) The table in this paragraph (a) shows the fees that you must pay to MMS for the services listed. The fees will be adjusted periodically according to the Implicit Price Deflator for Gross Domestic Product by publication of a document in the
(b) Payment of the fees listed in paragraph (a) of this section must accompany the submission of the document for approval or be sent to an office identified by the Regional Director. Once a fee is paid, it is nonrefundable, even if an application or other request is withdrawn. If your application is returned to you as incomplete, you are not required to submit a new fee when you submit the amended application.
(c) Verbal approvals are occasionally given in special circumstances. Any action that will be considered a verbal permit approval requires either a paper permit application to follow the verbal approval or an electronic application submittal within 72 hours. Payment must be made with the completed paper or electronic application.
You must file all payments electronically through
(a) If you submitted an application through eWell, you must use the interactive payment feature in that system, which directs you through
(b) For applications not submitted electronically through eWell, you must use credit card or automated clearing house (ACH) payments through the
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 regulations, the lease, right-of-way, the approved Exploration Plan or Development and Production Plans; or right-of-use and easement, and other applicable laws and regulations; and
(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 Manager's 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 Manager or Regional Supervisor.
(a) You must provide the Regional Supervisor an executed Designation of Operator form (Form MMS-1123) 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.
(d) If you change the designated operator on your lease, you must pay the service fee listed in § 250.125 of this subpart with your request for a change in designation of operator. Should there be multiple lessees, all designation of operator forms must be collected by one lessee and submitted to MMS in a single submittal, which is subject to only one filing fee.
(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
(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.
(f) You must pay a rental amount as required by paragraph (g) of this section if:
(1) You obtain a right-of-use and easement after January 12, 2004; or
(2) You ask MMS to modify your right-of-use and easement to change the footprint of the associated platform, artificial island, or installation or device.
(g) If you meet either of the conditions in paragraph (f) of this section, you must pay a rental amount to MMS as shown in the following table:
(h) You may make the rental payments required by paragraph (g)(1) and (g)(2) of this section on an annual basis, for a 5-year period, or for multiples of 5 years. You must make the first payment electronically through
(i)
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 (
(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 § 250.125; and
(b) The first year's rental as specified in § 250.160(g).
(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 (
(1) Must be in the form of a supplemental bond or bonds meeting the requirements of 30 CFR 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), (d), and (e)). The extension is equal to the
(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 (
(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);
(d) A commitment to production (SOP only); and
(e) The service fee listed in § 250.125 of this subpart.
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).
(a) 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.
(b) The Regional Supervisor may grant an SOO when all of the following conditions are met:
(1) The lease was issued with a primary lease term of 5 years, or with a primary term of 8 years with a requirement to drill within 5 years;
(2) Before the end of the third year of the primary term, you or your predecessor in interest must have acquired and interpreted geophysical information that indicates:
(i) The presence of a salt sheet;
(ii) That all or a portion of a potential hydrocarbon-bearing formation may lie beneath or adjacent to the salt sheet; and
(iii) The salt sheet interferes with identification of the potential hydrocarbon-bearing formation.
(3) The interpreted geophysical information required under paragraph (b)(2) of this section must include full 3-D depth migration beneath the salt sheet and over the entire lease area.
(4) Before requesting the suspension, you have conducted or are conducting additional data processing or interpretation of the geophysical information with the objective of identifying a potential hydrocarbon-bearing formation.
(5) You demonstrate that additional time is necessary to:
(i) complete current processing or interpretation of existing geophysical data or information;
(ii) acquire, process, or interpret new geophysical data or information; or
(iii) drill into the potential hydrocarbon-bearing formation identified as a result of the activities conducted in paragraphs (b)(2), (b)(4), and (b)(5) of this section.
(c) The Regional Supervisor may grant an SOO to conduct additional geological and geophysical data analysis that may lead to the drilling of a well below 25,000 feet true vertical depth below the datum at mean sea level (TVD SS) when all of the following conditions are met:
(1) The lease was issued with a primary lease term of:
(i) 5 years; or
(ii) 8 years with a requirement to drill within 5 years.
(2) Before the end of the fifth year of the primary term, you or your predecessor in interest must have acquired and interpreted geophysical information that:
(i) Indicates that all or a portion of a potential hydrocarbon-bearing formation lies below 25,000 feet TVD SS; and
(ii) Includes full 3-D depth migration over the entire lease area.
(3) Before requesting the suspension, you have conducted or are conducting additional data processing or interpretation of the geophysical information with the objective of identifying a potential hydrocarbon-bearing geologic structure or stratigraphic trap lying below 25,000 feet TVD SS.
(4) You demonstrate that additional time is necessary to:
(i) Complete current processing or interpretation of existing geophysical data or information;
(ii) Acquire, process, or interpret new geophysical or geological data or information that would affect the decision to drill the same geologic structure or stratigraphic trap, as determined by the Regional Supervisor, identified in paragraphs (c)(2) and (c)(3) of this section; or
(iii) Drill a well below 25,000 feet TVD SS into the geologic structure or stratigraphic trap identified as a result of the activities conducted in paragraphs
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 Manager 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
(f) When you begin conducting operations on a lease that has continued beyond its primary term, you must immediately notify the District Manager 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 Manager 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 Manager 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
(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 District Manager or Regional Supervisor.
(2) Instead of paper copies of forms available from the District Manager or Regional 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 § 250.197 or otherwise exempt from public disclosure under law or regulation.
(a) You must report all incidents listed in § 250.188(a) and (b) to the District Manager. The specific reporting requirements for these incidents are contained in §§ 250.189 and 250.190.
(b) These reporting requirements apply to incidents that occur on the area covered by your lease, right-of-use and easement, pipeline right-of-way, or other permit issued by MMS, and that are related to operations resulting from the exercise of your rights under your lease, right-of-use and easement, pipeline right-of-way, or permit.
(c) Nothing in this subpart relieves you from making notifications and reports of incidents that may be required by other regulatory agencies.
(d) You must report all spills of oil or other liquid pollutants in accordance with 30 CFR 254.46.
(a) You must report the following incidents to the District Manager immediately via oral communication, and provide a written follow-up report (hard copy or electronically transmitted) within 15 calendar days after the incident:
(1) All fatalities.
(2) All injuries that require the evacuation of the injured person(s) from the facility to shore or to another offshore facility.
(3) All losses of well control. “Loss of well control” means:
(i) Uncontrolled flow of formation or other fluids. The flow may be to an exposed formation (an underground blowout) or at the surface (a surface blowout);
(ii) Flow through a diverter; or
(iii) Uncontrolled flow resulting from a failure of surface equipment or procedures.
(4) All fires and explosions.
(5) All reportable releases of hydrogen sulfide (H
(6) All collisions that result in property or equipment damage greater than $25,000. “Collision” means the act of a moving vessel (including an aircraft) striking another vessel, or striking a stationary vessel or object (e.g., a boat striking a drilling rig or platform). “Property or equipment damage” means the cost of labor and material to restore all affected items to their condition before the damage, including, but not limited to, the OCS facility, a vessel, helicopter, or equipment. It does not include the cost of salvage, cleaning, gas-freeing, dry docking, or demurrage.
(7) All incidents involving structural damage to an OCS facility. “Structural damage” means damage severe enough so that operations on the facility cannot continue until repairs are made.
(8) All incidents involving crane or personnel/material handling operations.
(9) All incidents that damage or disable safety systems or equipment (including firefighting systems).
(b) You must provide a written report of the following incidents to the District Manager within 15 calendar days after the incident:
(1) Any injuries that result in one or more days away from work or one or more days on restricted work or job transfer. One or more days means the injured person was not able to return to work or to all of their normal duties the day after the injury occurred;
(2) All gas releases that initiate equipment or process shutdown;
(3) All incidents that require operations personnel on the facility to muster for evacuation for reasons not related to weather or drills;
(4) All other incidents, not listed in paragraph (a) of this section, resulting
For an incident requiring immediate notification under § 250.188(a), you must notify the District Manager via oral communication immediately after aiding the injured and stabilizing the situation. Your oral communication must provide the following information:
(a) Date and time of occurrence;
(b) Operator, and operator representative's, name and telephone number;
(c) Contractor, and contractor representative's name and telephone number (if a contractor is involved in the incident or injury/fatality);
(d) Lease number, OCS area, and block;
(e) Platform/facility name and number, or pipeline segment number;
(f) Type of incident or injury/fatality;
(g) Operation or activity at time of incident (
(h) Description of the incident, damage, or injury/fatality.
(a) For any incident covered under § 250.188, you must submit a written report within 15 calendar days after the incident to the District Manager. The report must contain the following information:
(1) Date and time of occurrence;
(2) Operator, and operator representative's name and telephone number;
(3) Contractor, and contractor representative's name and telephone number (if a contractor is involved in the incident or injury);
(4) Lease number, OCS area, and block;
(5) Platform/facility name and number, or pipeline segment number;
(6) Type of incident or injury;
(7) Operation or activity at time of incident (
(8) Description of incident, damage, or injury (including days away from work, restricted work or job transfer), and any corrective action taken; and
(9) Property or equipment damage estimate (in U.S. dollars).
(b) You may submit a report or form prepared for another agency in lieu of the written report required by paragraph (a) of this section, provided the report or form contains all required information.
(c) The District Manager may require you to submit additional information about an incident on a case-by-case basis.
Any investigation that MMS 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 adverse parties. The purpose of the investigation is to prepare a public report that determines the cause or causes of the incident. The investigation may involve panel meetings conducted by a chairperson appointed by MMS. The following requirements apply to any panel meetings involving persons giving testimony:
(a) A person giving testimony may have legal 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.
(b) Only panel members, and any experts the panel deems necessary, may address questions to any person giving testimony.
(c) The chairperson may issue subpoenas to persons to appear and provide testimony 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.
(d) Any person giving testimony may request compensation for mileage, and fees for services, within 90 days after the panel meeting. The compensated
(a) You must submit evacuation statistics to the Regional Supervisor for a natural occurrence, such as a hurricane, a tropical storm, or an earthquake. Statistics include facilities and rigs evacuated and the amount of production shut-in for gas and oil. You must:
(1) Submit the statistics by fax or e-mail (for activities in the MMS GOM OCS Region, use Form MMS-132) as soon as possible when evacuation occurs. In lieu of submitting your statistics by fax or e-mail, you may submit them electronically in accordance with 30 CFR 250.186(a)(3);
(2) Submit the statistics on a daily basis by 11 a.m., as conditions allow, during the period of shut-in and evacuation;
(3) Inform MMS when you resume production; and
(4) Submit the statistics either by MMS district, or the total figures for your operations in an MMS region.
(b) If your facility, production equipment, or pipeline is damaged by a natural occurrence, you must:
(1) Submit an initial damage report to the Regional Supervisor within 48 hours after you complete your initial evaluation of the damage. You must use Form MMS-143, Facility/Equipment Damage Report, to make this and all subsequent reports. In lieu of submitting Form MMS-143 by fax or e-mail, you may submit the damage report electronically in accordance with 30 CFR 250.186(a)(3). In the report, you must:
(i) Name the items damaged (e.g., platform or other structure, production equipment, pipeline);
(ii) Describe the damage and assess the extent of the damage (major, medium, minor); and
(iii) Estimate the time it will take to replace or repair each damaged structure and piece of equipment and return it to service. The initial estimate need not be provided on the form until availability of hardware and repair capability has been established (not to exceed 30 days from your initial report).
(2) Submit subsequent reports monthly and immediately whenever information submitted in previous reports changes until the damaged structure or equipment is returned to service. In the final report, you must provide the date the item was returned to service.
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 the Regional Director has reason to believe that an archaeological resource may exist in the lease area, the Regional Director will require in writing that your EP, DOCD, or DPP be accompanied by an archaeological report. 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
(c) If you discover any archaeological resource while conducting operations in the lease or right-of-way 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.
You must notify the appropriate MMS District Manager when you successfully complete or recomplete a well for production. You must:
(a) Notify the District Manager within 5 working days of placing the well in a production status. You must confirm oral notification by telefax or e-mail within those 5 working days.
(b) Provide the following information in your notification:
(1) Lessee or operator name;
(2) Well number, lease number, and OCS area and block designations;
(3) Date you placed the well on production (indicate whether or not this is first production on the lease);
(4) Type of production; and
(5) Measured depth of the production interval.
(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 that you submit under this part, and part 203 of this chapter, as described in this section. 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, under what circumstances, and in what time period. Paragraph (c) of this section describes what data and information will be made available for limited inspection without the consent of the lessee, and under what circumstances.
(a) All data and information you submit on MMS forms will be made available to the public upon submission, except as specified in the following table:
(b) MMS will release lease and permit data and information that you submit and MMS retains, but that are not normally submitted on MMS forms, according to the following table:
(c) MMS may allow limited inspection, but only by persons with a direct interest in related MMS decisions and issues in specific geographic areas, and who agree in writing to its confidentiality, of G&G data and information submitted under this part or part 203 of this chapter that MMS uses to:
(1) Make unitization determinations on two or more leases;
(2) Make competitive reservoir determinations;
(3) Ensure proper plans of development for competitive reservoirs;
(4) Promote operational safety;
(5) Protect the environment;
(6) Make field determinations; or
(7) Determine eligibility for royalty relief.
(a) The MMS is incorporating by reference the documents listed in paragraphs (e) through (k) of this section. Paragraphs (e) through (k) identify the publishing organization of the documents, the address and phone number where you may obtain these documents, and the documents incorporated
(1) Incorporation by reference of a document is limited to the edition of the publication that is cited in this section. Future amendments or revisions of the document are not included. The MMS will publish any changes to a document in the
(2) The 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) The MMS meets the requirements for making a rule immediately effective under 5 U.S.C. 553.
(3) The effect of incorporation by reference of a document into the regulations in this part is that the incorporated document is a requirement. When a section in this part incorporates all of a document, you are responsible for complying with the provisions of that entire document, except to the extent that section provides otherwise. When a section in this part incorporates part of a document, you are responsible for complying with that part of the document as provided in that section. If any incorporated document uses the word
(b) The 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 20170; phone: 703-787-1587; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:
(e) American Concrete Institute (ACI), ACI Standards, P. O. Box 9094, Farmington Hill, MI 48333-9094:
(1) ACI Standard 318-95, Building Code Requirements for Reinforced Concrete (ACI 318-95) and Commentary (ACI 318R-95), incorporated by reference at § 250.901(a), (d).
(2) ACI 357R-84, Guide for the Design and Construction of Fixed Offshore Concrete Structures, 1984; reapproved 1997, incorporated by reference at § 250.901(a), (d).
(f) American Institute of Steel Construction, Inc. (AISC), AISC Standards, One East Wacker Drive, Suite 700, Chicago, IL 60601-1802;
(1) ANSI/AISC 360-05, Specification for Structural Steel Buildings incorporated by reference at § 250.901(a), (d).
(2) [Reserved]
(g) American National Standards Institute (ANSI), ANSI/ASME Codes, ATTN: Sales Department, 25 West 43rd Street, 4th Floor, New York, NY 10036;
(1) ANSI/ASME Boiler and Pressure Vessel Code, Section I, Rules for Construction of Power Boilers; including Appendices, 2004 Edition; and July 1, 2005 Addenda, and all Section I Interpretations Volume 55, incorporated by reference at § 250.803(b)(1), (b)(1)(i); and § 250.1629(b)(1), (b)(1)(i);
(2) ANSI/ASME Boiler and Pressure Vessel Code, Section IV, Rules for Construction of Heating Boilers; including
(3) ANSI/ASME Boiler and Pressure Vessel Code, Section VIII, Rules for Construction of Pressure Vessels; Divisions 1 and 2, 2004 Edition; July 1, 2005 Addenda, Divisions 1 and 2, and all Section VIII Interpretations Volumes 54 and 55, incorporated by reference at § 250.803(b)(1), (b)(1)(i); and § 250.1629(b)(1), (b)(1)(i);
(4) ANSI/ASME B 16.5-2003, Pipe Flanges and Flanged Fittings incorporated by reference at § 250.1002(b)(2);
(5) ANSI/ASME B 31.8-2003, Gas Transmission and Distribution Piping Systems incorporated by reference at § 250.1002(a);
(6) ANSI/ASME SPPE-1-1994 and SPPE-1d-1996 Addenda, Quality Assurance and Certification of Safety and Pollution Prevention Equipment Used in Offshore Oil and Gas Operations, incorporated by reference at § 250.806(a)(2)(i);
(7) ANSI Z88.2-1992, American National Standard for Respiratory Protection, incorporated by reference at, § 250.490(g)(4)(iv), (j)(13)(ii).
(h) American Petroleum Institute (API), API Recommended Practices (RP), Specs, Standards, Manual of Petroleum Measurement Standards (MPMS) chapters, 1220 L Street, NW., Washington, DC 20005-4070;
(1) API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Downstream Segment, Ninth Edition, June 2006, Product No. C51009; incorporated by reference at § 250.803(b)(1); and § 250.1629(b)(1);
(2) API Bulletin 2INT-DG, Interim Guidance for Design of Offshore Structures for Hurricane Conditions, May 2007, Product No. G2DGINT; incorporated by reference at § 250.901(a), (d);
(3) API Bulletin 2INT-EX, Interim Guidance for Assessment of Existing Offshore Structures for Hurricane Conditions, May 2007, Product No. G2EXINT; incorporated by reference at § 250.901(a), (d);
(4) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico, May 2007, Product No. G2INTMET; incorporated by reference at § 250.901(a), (d);
(5) API MPMS, Chapter 1—Vocabulary, Second Edition, July 1994, Order No. 852-01002; incorporated by reference at § 250.1201;
(6) API MPMS, Chapter 2—Tank Calibration, Section 2A—Measurement and Calibration of Upright Cylindrical Tanks by the Manual Tank Strapping Method, First Edition, February 1995; reaffirmed February 2007, Order No. 852-022A1; incorporated by reference at § 250.1202(l)(4);
(7) API MPMS, Chapter 2—Tank Calibration, Section 2B—Calibration of Upright Cylindrical Tanks Using the Optical Reference Line Method, First Edition, March 1989; reaffirmed, December 2007, Order No. H30023; incorporated by reference at § 250.1202(l)(4);
(8) API MPMS, Chapter 3—Tank Gauging, Section 1A—Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition, August 2005, Product No. H301A02; incorporated by reference at § 250.1202(l)(4);
(9) API MPMS, Chapter 3—Tank Gauging, Section 1B—Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second Edition, June 2001, reaffirmed, October 2006, Product No. H301B2; incorporated by reference at § 250.1202(l)(4);
(10) API MPMS, Chapter 4—Proving Systems, Section 1—Introduction, Third Edition, February 2005, Product No. H04013; incorporated by reference at § 250.1202(a)(3), (f)(1);
(11) API MPMS, Chapter 4—Proving Systems, Section 2—Displacement Provers, Third Edition, September 2003, Product No. H04023; incorporated by reference at § 250.1202(a)(3), (f)(1);
(12) API MPMS, Chapter 4—Proving Systems, Section 4—Tank Provers, Second Edition, May 1998, reaffirmed November 2005, Order No. H04042; incorporated by reference at § 250.1202(a)(3), (f)(1);
(13) API MPMS, Chapter 4—Proving Systems, Section 5—Master-Meter
(14) API MPMS, Chapter 4—Proving Systems, Section 6—Pulse Interpolation, Second Edition, May 1999; reaffirmed 2003, Order No. H04062; incorporated by reference at § 250.1202(a)(3), (f)(1);
(15) API MPMS, Chapter 4—Proving Systems, Section 7—Field Standard Test Measures, Second Edition, December 1998; reaffirmed 2003, Order No. H04072; incorporated by reference at § 250.1202(a)(3), (f)(1);
(16) API MPMS, Chapter 5—Metering, Section 1—General Considerations for Measurement by Meters, Fourth Edition, September 2005, Product No. H05014; incorporated by reference at § 250.1202(a)(3);
(17) API MPMS, Chapter 5—Metering, Section 2—Measurement of Liquid Hydrocarbons by Displacement Meters, Third Edition, September 2005, Product No. H05023; incorporated by reference at § 250.1202(a)(3);
(18) API MPMS Chapter 5—Metering, Section 3—Measurement of Liquid Hydrocarbons by Turbine Meters, Fifth Edition, September 2005, Product No. H05035; incorporated by reference at § 250.1202(a)(3);
(19) API MPMS, Chapter 5—Metering, Section 4—Accessory Equipment for Liquid Meters, Fourth Edition, September 2005, Product No. H05044; incorporated by reference at § 250.1202(a)(3);
(20) API MPMS, Chapter 5—Metering, Section 5—Fidelity and Security of Flow Measurement Pulsed-Data Transmission Systems, Second Edition, August 2005, Product No. H50502; incorporated by reference at § 250.1202(a)(3);
(21) API MPMS, Chapter 6—Metering Assemblies, Section 1—Lease Automatic Custody Transfer (LACT) Systems, Second Edition, May 1991; reaffirmed, April 2007, Order No. H30121; incorporated by reference at § 250.1202(a)(3);
(22) API MPMS, Chapter 6—Metering Assemblies, Section 6—Pipeline Metering Systems, Second Edition, May 1991; reaffirmed, February 2007, Order No. 852-30126; incorporated by reference at § 250.1202(a)(3);
(23) API MPMS, Chapter 6—Metering Assemblies, Section 7—Metering Viscous Hydrocarbons, Second Edition, May 1991; reaffirmed, April 2007, Order No. 852-30127; incorporated by reference at § 250.1202(a)(3);
(24) API MPMS, Chapter 7—Temperature Determination, First Edition, June 2001; reaffirmed, March 2007; Product No. H07001; incorporated by reference at § 250.1202(a)(3), (l)(4);
(25) API MPMS, Chapter 8—Sampling, Section 1—Standard Practice for Manual Sampling of Petroleum and Petroleum Products, Third Edition, October 1995; reaffirmed, March 2006, Order No. H08013; incorporated by reference at § 250.1202(b)(4)(i), (l)(4);
(26) API MPMS, Chapter 8—Sampling, Section 2—Standard Practice for Automatic Sampling of Liquid Petroleum and Petroleum Products, Second Edition, October 1995; reaffirmed, June 2005, Order No. H08022; incorporated by reference at § 250.1202(a)(3), (l)(4);
(27) API MPMS, Chapter 9—Density Determination, Section 1—Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, Second Edition, December 2002; reaffirmed October 2005, Product No. H09012; incorporated by reference at § 250.1202(a)(3), (l)(4);
(28) API MPMS, Chapter 9—Density Determination, Section 2—Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer, Second Edition, March 2003, Product No. H09022; incorporated by reference at § 250.1202(a)(3), (l)(4);
(29) API MPMS, Chapter 10—Sediment and Water, Section 1—Standard Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction Method, Third Edition, November 2007, Product No. H10013; incorporated by reference at § 250.1202(a)(3), (l)(4);
(30) API MPMS, Chapter 10—Sediment and Water, Section 2—Standard Test Method for Water in Crude Oil by Distillation, Second Edition, November 2007, Product No. H10022; incorporated by reference at § 250.1202(a)(3), (l)(4);
(31) API MPMS, Chapter 10—Sediment and Water, Section 3—Standard Test Method for Water and Sediment in
(32) API MPMS, Chapter 10—Sediment and Water, Section 4—Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure), Third Edition, December 1999, Order No. H10043; incorporated by reference at § 250.1202(a)(3), (l)(4);
(33) API MPMS, Chapter 10—Sediment and Water, Section 9—Standard Test Method for Water in Crude Oils by Coulometric Karl Fischer Titration, Second Edition, December 2002; reaffirmed 2005, Product No. H10092; incorporated by reference at § 250.1202(a)(3), (l)(4);
(34) API MPMS, Chapter 11.1—Volume Correction Factors, Volume 1, Table 5A—Generalized Crude Oils and JP-4 Correction of Observed API Gravity to API Gravity at 60 °F, and Table 6A—Generalized Crude Oils and JP-4 Correction of Volume to 60 °F Against API Gravity at 60 °F, API Standard 2540, First Edition, August 1980; reaffirmed March 1997, API Stock No. H27000; incorporated by reference at § 250.1202(a)(3), (g)(3), (l)(4);
(35) API MPMS, Chapter 11.2.2—Compressibility Factors for Hydrocarbons: 0.350-0.637 Relative Density (60 °F/60 °F) and −50 °F to 140 °F Metering Temperature, Second Edition, October 1986; reaffirmed: December 2007, Order No. 852-27307; incorporated by reference at § 250.1202(a)(3), (g)(4);
(36) API MPMS, Chapter 11—Physical Properties Data, Addendum to Section 2, Part 2—Compressibility Factors for Hydrocarbons, Correlation of Vapor Pressure for Commercial Natural Gas Liquids, First Edition, December 1994; reaffirmed, December 2002, Order No. H27308; incorporated by reference at § 250.1202(a)(3);
(37) API MPMS, Chapter 12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 1—Introduction, Second Edition, May 1995; reaffirmed March 2002, Order No. H12021; incorporated by reference at § 250.1202(a)(3), (g)(1), (g)(2);
(38) API MPMS, Chapter 12—Calculation of Petroleum Quantities, Section 2—Calculation of Petroleum Quantities Using Dynamic Measurement Methods and Volumetric Correction Factors, Part 2—Measurement Tickets, Third Edition, June 2003, Product No. H12223; incorporated by reference at § 250.1202(a)(3), (g)(1), (g)(2);
(39) API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters, Part 1—General Equations and Uncertainty Guidelines, Third Edition, September 1990; reaffirmed January 2003, Order No. 852-30350; incorporated by reference at § 250.1203(b)(2);
(40) API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters, Part 2—Specification and Installation Requirements, Fourth Edition, April 2000; reaffirmed March 2006, Order No. H14324; incorporated by reference at § 250.1203(b)(2);
(41) API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 3—Concentric, Square-Edged Orifice Meters; Part 3—Natural Gas Applications; Third Edition, August 1992; Errata March 1994, reaffirmed, February 2009, Product No. H143303; incorporated by reference at § 250.1203(b)(2);
(42) API MPMS, Chapter 14.5/GPA Standard 2172-09; Calculation of Gross Heating Value, Relative Density, Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for Custody Transfer; Third Edition, January 2009; Adopted as Tentative Standard, 1972; Revised and Adopted as Standard, 1976; Revised 1984, 1986, 1996, 2009; Product No. H140503; incorporated by reference at § 250.1203(b)(2);
(43) API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 6—Continuous Density Measurement, Second Edition, April 1991; reaffirmed, February 2006, Order No. H30346; incorporated by reference at § 250.1203(b)(2);
(44) API MPMS, Chapter 14—Natural Gas Fluids Measurement, Section 8—Liquefied Petroleum Gas Measurement, Second Edition, July 1997; reaffirmed, March 2006, Order No. H14082; incorporated by reference at § 250.1203(b)(2);
(45) API MPMS, Chapter 20—Section 1—Allocation Measurement, First Edition, September 1993; reaffirmed October 2006, Order No. 852-30701; incorporated by reference at § 250.1202(k)(1);
(46) API MPMS, Chapter 21—Flow Measurement Using Electronic Metering Systems, Section 1—Electronic Gas Measurement, First Edition, August 1993; reaffirmed, July 2005, Order No. 852-30730; incorporated by reference at § 250.1203(b)(4);
(47) API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms—Working Stress Design, Twenty-first Edition, December 2000; Errata and Supplement 1, December 2002; Errata and Supplement 2, September 2005; Errata and Supplement 3, October 2007; Product No. G2AWSD; incorporated by reference at § 250.901(a), (d); § 250.908(a); § 250.919(b)(2); § 250.920(a), (b), (c), (d), (e), (f);
(48) API RP 2D, Operation and Maintenance of Offshore Cranes, Sixth Edition, May 2007, Product No. G02D06; incorporated by reference at § 250.108(a);
(49) API RP 2FPS, RP for Planning, Designing, and Constructing Floating Production Systems; First Edition, March 2001, Order No. G2FPS1; incorporated by reference at § 250.901(a), (d);
(50) API RP 2I, In-Service Inspection of Mooring Hardware for Floating Structures; Third Edition, April 2008, Product No. G02I03; incorporated by reference at § 250.901(a), (d);
(51) API RP 2RD, Recommended Practice for Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), First Edition, June 1998; reaffirmed, May 2006, Errata, June 2009; Order No. G02RD1; incorporated by reference at § 250.800(b)(2); § 250.901(a), (d); § 250.1002(b)(5);
(52) API RP 2SK, Design and Analysis of Stationkeeping Systems for Floating Structures, Third Edition, October 2005, Addendum, May 2008, Product No. G2SK03; incorporated by reference at § 250.800(b)(3); § 250.901(a), (d);
(53) API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, March 2001, Addendum, May 2007, Product No. G02SM1; incorporated by reference at § 250.901(a), (d);
(54) API RP 2T, Recommended Practice for Planning, Designing, and Constructing Tension Leg Platforms, Second Edition, August 1997, Order No. G02T02; incorporated by reference at § 250.901(a), (d);
(55) API RP 14B, Recommended Practice for Design, Installation, Repair and Operation of Subsurface Safety Valve Systems, Fifth Edition, October 2005, also available as ISO 10417: 2004, (Identical) Petroleum and natural gas industries—Subsurface safety valve systems—Design, installation, operation and redress, Product No. GX14B05; incorporated by reference at § 250.801(e)(4); § 250.804(a)(1)(i);
(56) API RP 14C, Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms, Seventh Edition, March 2001, reaffirmed: March 2007; Product No. C14C07; incorporated by reference at § 250.125(a); § 250.292(j); § 250.802(b), (e)(2); § 250.803(a), (b)(2)(i), (b)(4), (b)(5)(i), (b)(7), (b)(9)(v), (c)(2); § 250.804(a), (a)(6); § 250.1002(d); § 250.1004(b)(9); § 250.1628(c), (d)(2); § 250.1629(b)(2), (b)(4)(v); § 250.1630(a);
(57) API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems, Fifth Edition, October 1991; reaffirmed, March 2007, Order No. 811-07185; incorporated by reference at § 250.802(e)(3); § 250.1628(b)(2), (d)(3);
(58) API RP 14F, Design, Installation, and Maintenance of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Division 1 and Division 2 Locations, Fifth Edition, July 2008, Product No. G14F05; incorporated by reference at § 250.114(c); § 250.803(b)(9)(v); § 250.1629(b)(4)(v);
(59) API RP 14FZ, Recommended Practice for Design and Installation of Electrical Systems for Fixed and Floating Offshore Petroleum Facilities for Unclassified and Class I, Zone 0, Zone 1 and Zone 2 Locations, First Edition, September 2001, reaffirmed: March 2007; Product No. G14FZ1; incorporated by reference at § 250.114(c); § 250.803(b)(9)(v); § 250.1629(b)(4)(v);
(60) API RP 14G, Recommended Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms, Fourth Edition, April 2007; Product No. G14G04; incorporated by reference at § 250.803(b)(8), (b)(9)(v); § 250.1629(b)(3), (b)(4)(v);
(61) API RP 14H, Recommended Practice for Installation, Maintenance and Repair of Surface Safety Valves and Underwater Safety Valves Offshore, Fifth Edition, August 2007, Product No. G14H05; incorporated by reference at § 250.802(d); § 250.804(a)(5);
(62) API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, Second Edition, May 2001; reaffirmed: March 2007; Product No. G14J02; incorporated by reference at § 250.800(b)(1); § 250.901(a)(14);
(63) API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells, Third Edition, March 1997; reaffirmed September 2004, Order No. G53003; incorporated by reference at § 250.442(c); § 250.446(a); § 250.516(g)(1); § 250.516(h); and § 250.617(a)(1), and (b);
(64) API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deepwater Wells, First Edition, September 2002, Product No. G56001; incorporated by reference at § 250.415(e);
(65) API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2, Second Edition, November 1997; reaffirmed November 2002, Product No. C50002; incorporated by reference at § 250.114(a); § 250.459; § 250.802(e)(4)(i); § 250.803(b)(9)(i); § 250.1628(b)(3), (d)(4)(i); § 250.1629(b)(4)(i);
(66) 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, First Edition, November 1997; reaffirmed November 2002, Order No. C50501; incorporated by reference at § 250.114(a); § 250.459; § 250.802(e)(4)(i); § 250.803(b)(9)(i); § 250.1628(b)(3), (d)(4)(i); § 250.1629(b)(4)(i);
(67) API RP 2556, Recommended Practice for Correcting Gauge Tables for Incrustation, Second Edition, August 1993; reaffirmed November 2003, Order No. H25560; incorporated by reference at § 250.1202(l)(4);
(68) ANSI/API Spec. Q1, Specification for Quality Programs for the Petroleum, Petrochemical and Natural Gas Industry, ISO TS 29001:2007 (Identical), Petroleum, petrochemical and natural gas industries—Sector specific requirements—Requirements for product and service supply organizations, Eighth Edition, December 2007, Effective Date: June 15, 2008, Product No. GXQ108; incorporated by reference at § 250.806(a)(2)(ii);
(69) API Spec. 2C, Specification for Offshore Pedestal Mounted Cranes, Sixth Edition, March 2004, Effective Date: September 2004, Product No. G02C06; incorporated by reference at § 250.108(c), (d);
(70) ANSI/API Spec. 6A, Specification for Wellhead and Christmas Tree Equipment, Nineteenth Edition, July 2004; Effective Date: February 1, 2005; Contains API Monogram Annex as Part of U.S. National Adoption; ISO 10423:2003 (Modified), Petroleum and natural gas industries—Drilling and production equipment—Wellhead and Christmas tree equipment; Errata 1, September 2004, Errata 2, April 2005, Errata 3, June 2006, Errata 4, August 2007, Errata 5, May 2009; Addendum 1, February 2008; Addendum 2, 3, and 4, December 2008; Product No. GX06A19; incorporated by reference at § 250.806(a)(3); § 250.1002(b)(1), (b)(2);
(71) API Spec. 6AV1, Specification for Verification Test of Wellhead Surface Safety Valves and Underwater Safety Valves for Offshore Service, First Edition, February 1, 1996; reaffirmed January 2003, Order No. G06AV1; incorporated by reference at § 250.806(a)(3);
(72) ANSI/API Spec. 6D, Specification for Pipeline Valves, Twenty-third Edition, April 2008; Effective Date: October 1, 2008, Errata 1, June 2008; Errata 2, November 2008; Errata 3, February 2009; Addendum 1, October 2009; Contains API Monogram Annex as Part of U.S. National Adoption; ISO 14313:2007 (Identical), Petroleum and natural gas industries—Pipeline transportation systems—Pipeline valves; Product No. GX6D23; incorporated by reference at § 250.1002(b)(1);
(73) ANSI/API Spec. 14A, Specification for Subsurface Safety Valve Equipment, Eleventh Edition, October 2005, Effective Date: May 1, 2006; also available as ISO 10432:2004, Product No. GX14A11; incorporated by reference at § 250.806(a)(3);
(74) ANSI/API Spec. 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008; Effective Date: January 1, 2009, Contains API Monogram Annex as Part of U.S. National Adoption; ISO 13628-2:2006 (Identical), Petroleum and natural gas industries—Design and operation of subsea production systems—Part 2: Unbonded flexible pipe systems for subsea and marine application; Product No. GX17J03; incorporated by reference at § 250.803(b)(2)(iii); § 250.1002(b)(4); § 250.1007(a)(4);
(75) API Standard 2551, Measurement and Calibration of Horizontal Tanks, First Edition, 1965; reaffirmed March 2002, API Stock No. H25510; incorporated by reference at § 250.1202(l)(4);
(76) API Standard 2552, USA Standard Method for Measurement and Calibration of Spheres and Spheroids, First Edition, 1966; reaffirmed, October 2007 (ASTM designation: D 1408-65; date of joint API/ASTM approval, 1965); incorporated by reference at § 250.1202(l)(4);
(77) API Standard 2555, Method for Liquid Calibration of Tanks, First Edition, September 1966; reaffirmed March 2002; Order No. 852-25550; incorporated by reference at § 250.1202(l)(4).
(78) API RP 90, Annular Casing Pressure Management for Offshore Wells, First Edition, August 2006, Product No. G09001, incorporated by reference at § 250.518.
(79) API RP 65-Part 2, Isolating Potential Flow Zones During Well Construction; First Edition, May 2010; Product No. G65201; incorporated by reference at § 250.415(f).
(80) API RP 75, Recommended Practice for Development of a Safety and Environmental Management Program for Offshore Operations and Facilities, Third Edition, May 2004, Reaffirmed May 2008, Product No. G07503; incorporated by reference at § § 250.1900, 250.1900(c), 250.1902(c), 250.1903, 250.1909, 250.1920(a) and (b).
(i) American Society for Testing and Materials (ASTM), ASTM Standards, 100 Bar Harbor Drive, P. O. Box C700, West Conshohocken, PA 19428-2959;
(1) ASTM Standard C 33-07, approved December 15, 2007, Standard Specification for Concrete Aggregates; incorporated by reference at § 250.901(a), (d);
(2) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard Specification for Ready-Mixed Concrete; incorporated by reference at § 250.901(a), (d);
(3) ASTM Standard C 150-07, approved May 1, 2007, Standard Specification for Portland Cement; incorporated by reference at § 250.901(a), (d);
(4) ASTM Standard C 330-05, approved December 15, 2005, Standard Specification for Lightweight Aggregates for Structural Concrete; incorporated by reference at § 250.901(a), (d);
(5) ASTM Standard C 595-08, approved January 1, 2008, Standard Specification for Blended Hydraulic Cements; incorporated by reference at § 250.901(a), (d);
(j) American Welding Society (AWS), AWS Codes, 550 NW, LeJeune Road, Miami, FL 33126;
(1) AWS D1.1:2000, Structural Welding Code—Steel; incorporated by reference at § 250.901(a), (d);
(2) AWS D1.4-98, Structural Welding Code—Reinforcing Steel; incorporated by reference at § 250.901(a), (d);
(3) AWS D3.6M:1999, Specification for Underwater Welding; incorporated by reference at § 250.901(a), (d).
(k) National Association of Corrosion Engineers (NACE), NACE Standards, 1440 South Creek Drive, Houston, TX 77084;
(1) NACE Standard MR0175-2003, Item No. 21302, Standard Material Requirements, Metals for Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour Oilfield Environments; incorporated by reference at § 250.901(a), § 250.490(p)(2);
(2) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended Practice, Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production; incorporated by reference at § 250.901(a), (d).
(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 5438, 1849 C Street, NW., Washington, DC 20240.
(e) MMS is collecting this information for the reasons given in the following table:
Acronyms and terms used in this subpart have the following meanings:
(a)
(b)
(1) Have not been used previously or extensively in an MMS OCS Region;
(2) Have not been used previously under the anticipated operating conditions; or
(3) Have operating characteristics that are outside the performance parameters established by this part.
(a)
(b)
(c)
(1) Sufficient applicable information or analysis is readily available to MMS;
(2) Other coastal or marine resources are not present or affected;
(3) Other factors such as technological advances affect information needs; or
(4) Information is not necessary or required for a State to determine consistency with their CZMA Plan.
(d)
Your EP, DPP, or DOCD must demonstrate that you have planned and are prepared to conduct the proposed activities in a manner that:
(a) Conforms to the Outer Continental Shelf Lands Act as amended (Act), applicable implementing regulations, lease provisions and stipulations, and other Federal laws;
(b) Is safe;
(c) Conforms to sound conservation practices and protects the rights of the lessor;
(d) Does not unreasonably interfere with other uses of the OCS, including those involved with national security or defense; and
(e) Does not cause undue or serious harm or damage to the human, marine, or coastal environment.
The Regional Supervisor reviews and approves proposed well location and spacing under an EP, DPP, or DOCD. In deciding whether to approve a proposed well location and spacing, the Regional Supervisor will consider factors including, but not limited to, the following:
(a) Protecting correlative rights;
(b) Protecting Federal royalty interests;
(c) Recovering optimum resources;
(d) Number of wells that can be economically drilled for proper reservoir management;
(e) Location of drilling units and platforms;
(f) Extent and thickness of the reservoir;
(g) Geologic and other reservoir characteristics;
(h) Minimizing environmental risk;
(i) Preventing unreasonable interference with other uses of the OCS; and
(j) Drilling of unnecessary wells.
(a) To protect the rights of the Federal government, you must either:
(1) Drill and produce the wells that the Regional Supervisor determines are necessary to protect the Federal government from loss due to production on other leases or units or from adjacent lands under the jurisdiction of other entities (e.g., State and foreign governments); or
(2) Pay a sum that the Regional Supervisor determines as adequate to compensate the Federal government for your failure to drill and produce any well.
(b) Payment under paragraph (a)(2) of this section may constitute production in paying quantities for the purpose of extending the lease term.
(c) You must complete and produce any penetrated hydrocarbon-bearing zone that the Regional Supervisor determines is necessary to conform to sound conservation practices.
For wells that could intersect or drain an adjacent property, the Regional Supervisor may require special measures to protect the rights of the Federal government and objecting lessees or operators of adjacent leases or units.
(a)
(1) Four copies that contain all required information (proprietary copies);
(2) Eight copies for public distribution (public information copies) that omit information that you assert is exempt from disclosure under the Freedom of Information Act (FOIA) (5 U.S.C. 552) and the implementing regulations (43 CFR part 2); and
(3) Any additional copies that may be necessary to facilitate review of the EP, DPP, or DOCD by certain affected States and other reviewing entities.
(b)
(c)
Before or after you submit an EP, DPP, or DOCD to MMS, you may elect, the regulations in this part may require, or the Regional Supervisor may direct you to conduct ancillary activities. Ancillary activities include:
(a) Geological and geophysical (G&G) explorations and development G&G activities;
(b) Geological and high-resolution geophysical, geotechnical, archaeological, biological, physical oceanographic, meteorological, socioeconomic, or other surveys; or
(c) Studies that model potential oil and hazardous substance spills, drilling muds and cuttings discharges, projected air emissions, or potential hydrogen sulfide (H
At least 30 calendar days before you conduct any G&G exploration or development G&G activity (see § 250.207(a)), you must notify the Regional Supervisor in writing.
(a) When you prepare the notice, you must:
(1) Sign and date the notice;
(2) Provide the names of the vessel, its operator, and the person(s) in charge; the specific type(s) of operations you will conduct; and the instrumentation/techniques and vessel navigation system you will use;
(3) Provide expected start and completion dates and the location of the activity; and
(4) Describe the potential adverse environmental effects of the proposed activity and any mitigation to eliminate or minimize these effects on the marine, coastal, and human environment.
(b) The Regional Supervisor may require you to:
(1) Give written notice to MMS at least 15 calendar days before you conduct any other ancillary activity (see § 250.207(b) and (c)) in addition to those listed in § 250.207(a); and
(2) Notify other users of the OCS before you conduct any ancillary activity.
The Regional Supervisor will review any notice required under § 250.208(a) and (b)(1) to ensure that your ancillary activity complies with the performance standards listed in § 250.202(a), (b), (d), and (e). The Regional Supervisor may notify you that your ancillary activity does not comply with those standards. In such a case, the Regional Supervisor will require you to submit an EP, DPP, or DOCD and you may not start your ancillary activity until the Regional Supervisor approves the EP, DPP, or DOCD.
(a)
(b)
Your EP must include the following:
(a)
(b)
(c)
(d)
The following information must accompany your EP:
(a) General information required by § 250.213;
(b) Geological and geophysical (G&G) information required by § 250.214;
(c) Hydrogen sulfide information required by § 250.215;
(d) Biological, physical, and socioeconomic information required by § 250.216;
(e) Solid and liquid wastes and discharges information and cooling water intake information required by § 250.217;
(f) Air emissions information required by § 250.218;
(g) Oil and hazardous substance spills information required by § 250.219;
(h) Alaska planning information required by § 250.220;
(i) Environmental monitoring information required by § 250.221;
(j) Lease stipulations information required by § 250.222;
(k) Mitigation measures information required by § 250.223;
(l) Support vessels and aircraft information required by § 250.224;
(m) Onshore support facilities information required by § 250.225;
(n) Coastal zone management information required by § 250.226;
(o) Environmental impact analysis information required by § 250.227; and
(p) Administrative information required by § 250.228.
The following general information must accompany your EP:
(a)
(b)
(c)
(d)
(e)
(1) The activities and facilities proposed in your EP are or will be covered by an appropriate bond under 30 CFR part 256, subpart I;
(2) You have demonstrated or will demonstrate oil spill financial responsibility for facilities proposed in your EP according to 30 CFR part 253; and
(3) You have or will have the financial capability to drill a relief well and conduct other emergency well control operations.
(f)
(g)
(h)
The following G&G information must accompany your EP:
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
The following H
(a)
(b)
(c)
(d)
(1) The analysis in the modeling report must be specific to the particular site of your proposed exploration activities, and must consider any nearby human-occupied OCS facilities, shipping lanes, fishery areas, and other points where humans may be subject to potential exposure from an H
(2) If any H
If you obtain the following information in developing your EP, or if the Regional Supervisor requires you to obtain it, you must include a report, or the information obtained, or a reference to such a report or information if you have already submitted it to the Regional Supervisor, as accompanying information:
(a)
(b)
(c)
The following solid and liquid wastes and discharges information and cooling water intake information must accompany your EP:
(a)
(1) The methods you used for determining this information; and
(2) Your plans for treating, storing, and downhole disposal of these wastes at your drilling location(s).
(b)
(1) A table showing the name, projected amount, and rate of discharge for each waste type; and
(2) A description of the discharge method (such as shunting through a downpipe, etc.) you will use.
(c)
(2) A copy of your application for an individual NPDES permit. Briefly describe the major discharges and methods you will use for compliance.
(d)
(e)
The following air emissions information, as applicable, must accompany your EP:
(a)
(1) For each source on or associated with the drilling unit (including well test flaring and well protection structure installation), you must list:
(i) The projected peak hourly emissions;
(ii) The total annual emissions in tons per year;
(iii) Emissions over the duration of the proposed exploration activities;
(iv) The frequency and duration of emissions; and
(v) The total of all emissions listed in paragraphs (a)(1)(i) through (iv) of this section.
(2) You must provide the basis for all calculations, including engine size and rating, and applicable operational information.
(3) You must base the projected emissions on the maximum rated capacity of the equipment on the proposed drilling unit under its physical and operational design.
(4) If the specific drilling unit has not yet been determined, you must use the maximum emission estimates for the type of drilling unit you will use.
(b)
(c)
(d)
(e)
(f)
The following information regarding potential spills of oil (see definition under 30 CFR 254.6) and hazardous substances (see definition under 40 CFR part 116) as applicable, must accompany your EP:
(a)
(1) An Oil Spill Response Plan (OSRP) for the facilities you will use to conduct your exploration activities prepared according to the requirements of 30 CFR part 254, subpart B; or
(2) Reference to your approved regional OSRP (see 30 CFR 254.3) to include:
(i) A discussion of your regional OSRP;
(ii) The location of your primary oil spill equipment base and staging area;
(iii) The name(s) of your oil spill removal organization(s) for both equipment and personnel;
(iv) The calculated volume of your worst case discharge scenario (see 30 CFR 254.26(a)), and a comparison of the appropriate worst case discharge scenario in your approved regional OSRP with the worst case discharge scenario that could result from your proposed exploration activities; and
(v) A description of the worst case discharge scenario that could result from your proposed exploration activities (see 30 CFR 254.26(b), (c), (d), and (e)).
(b)
If you propose exploration activities in the Alaska OCS Region, the following planning information must accompany your EP:
(a)
(b)
The following environmental monitoring information, as applicable, must accompany your EP:
(a)
(b)
(1) Threatened and endangered species listed under the ESA and
(2) Marine mammals, as appropriate, if you have not already received authorization for incidental take as may be necessary under the MMPA.
(c)
A description of the measures you took, or will take, to satisfy the conditions of lease stipulations related to your proposed exploration activities must accompany your EP.
(a) If you propose to use any measures beyond those required by the regulations in this part to minimize or mitigate environmental impacts from your proposed exploration activities, a description of the measures you will use must accompany your EP.
(b) If there is reason to believe that protected species may be incidentally taken by planned exploration activities, you must include mitigation measures designed to avoid or minimize the incidental take of:
(1) Threatened and endangered species listed under the ESA and
(2) Marine mammals, as appropriate, if you have not already received authorization for incidental take as may be necessary under the MMPA.
The following information on the support vessels, offshore vehicles, and aircraft you will use must accompany your EP:
(a)
(b)
(c)
(d)
(e)
The following information on the onshore support facilities you will use must accompany your EP:
(a)
(1) Indicate whether the onshore support facilities are existing, to be constructed, or to be expanded.
(2) If the onshore support facilities are, or will be, located in areas not adjacent to the Western GOM, provide a timetable for acquiring lands (including rights-of-way and easements) and constructing or expanding the facilities. Describe any State or Federal permits or approvals (dredging, filling, etc.) that would be required for constructing or expanding them.
(b)
(c)
(d)
The following CZMA information must accompany your EP:
(a)
(b)
The following EIA information must accompany your EP:
(a)
(1) Assess the potential environmental impacts of your proposed exploration activities;
(2) Be project specific; and
(3) Be as detailed as necessary to assist the Regional Supervisor in complying with the National Environmental Policy Act (NEPA) of 1969 (42 U.S.C. 4321
(b)
(1) Meteorology, oceanography, geology, and shallow geological or manmade hazards;
(2) Air and water quality;
(3) Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, and plant life;
(4) Threatened or endangered species and their critical habitat as defined by the Endangered Species Act of 1973;
(5) Sensitive biological resources or habitats such as essential fish habitat, refuges, preserves, special management areas identified in coastal management programs, sanctuaries, rookeries, and calving grounds;
(6) Archaeological resources;
(7) Socioeconomic resources including employment, existing offshore and coastal infrastructure (including major sources of supplies, services, energy, and water), land use, subsistence resources and harvest practices, recreation, recreational and commercial fishing (including typical fishing seasons, location, and type), minority and lower income groups, and coastal zone management programs;
(8) Coastal and marine uses such as military activities, shipping, and mineral exploration or development; and
(9) Other resources, conditions, and activities identified by the Regional Supervisor.
(c)
(1) Analyze the potential direct and indirect impacts (including those from accidents, cooling water intake structures, and those identified in relevant ESA biological opinions such as, but not limited to, those from noise, vessel collisions, and marine trash and debris) that your proposed exploration activities will have on the identified resources, conditions, and activities;
(2) Analyze any potential cumulative impacts from other activities to those identified resources, conditions, and
(3) Describe the type, severity, and duration of these potential impacts and their biological, physical, and other consequences and implications;
(4) Describe potential measures to minimize or mitigate these potential impacts; and
(5) Summarize the information you incorporate by reference.
(d)
(e)
The following administrative information must accompany your EP:
(a)
(b)
(2) The location(s) where the Regional Supervisor can inspect the cited referenced material if you have not submitted it.
(a)
(1) The submitted information, including the information that must accompany the EP (refer to the list in § 250.212), fulfills requirements and is sufficiently accurate;
(2) You have provided all needed additional information (see § 250.201(b)); and
(3) You have provided the required number of copies (see § 250.206(a)).
(b)
(c)
(a)
(1)
(2)
(b)
(c)
(d)
(a)
(b)
(a)
(b)
(c)
If an affected State objects to the coastal zone consistency certification accompanying your proposed EP within the timeframe prescribed in § 250.233(a) or § 250.234(c), you may do one of the following:
(a)
(b)
(1) Grant your appeal by finding, under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), that each activity described in detail in your EP is consistent with the objectives of the CZMA, or is otherwise necessary in the interest of national security; or
(2) Deny your appeal, in which case you may amend your EP as described in paragraph (a) of this section.
(c)
Your DPP or DOCD must include the following:
(a)
(1) Development drilling;
(2) Well test flaring;
(3) Installation of production platforms, satellite structures, subsea wellheads and manifolds, and lease term pipelines (see definition at § 250.105); and
(4) Installation of production facilities and conduct of production operations.
(b)
(c)
(d)
(e)
The following information must accompany your DPP or DOCD.
(a) General information required by § 250.243;
(b) G&G information required by § 250.244;
(c) Hydrogen sulfide information required by § 250.245;
(d) Mineral resource conservation information required by § 250.246;
(e) Biological, physical, and socioeconomic information required by § 250.247;
(f) Solid and liquid wastes and discharges information and cooling water intake information required by § 250.248;
(g) Air emissions information required by § 250.249;
(h) Oil and hazardous substance spills information required by § 250.250;
(i) Alaska planning information required by § 250.251;
(j) Environmental monitoring information required by § 250.252;
(k) Lease stipulations information required by § 250.253;
(l) Mitigation measures information required by § 250.254;
(m) Decommissioning information required by § 250.255;
(n) Related facilities and operations information required by § 250.256;
(o) Support vessels and aircraft information required by § 250.257;
(p) Onshore support facilities information required by § 250.258;
(q) Sulphur operations information required by § 250.259;
(r) Coastal zone management information required by § 250.260;
(s) Environmental impact analysis information required by § 250.261; and
(t) Administrative information required by § 250.262.
The following general information must accompany your DPP or DOCD:
(a)
(b)
(c)
(1) Estimates of the average and peak rates of production for each type of production and the life of the reservoir(s) you intend to produce; and
(2) The chemical and physical characteristics of the produced oil (see definition under 30 CFR 254.6) that you will handle or store at the facilities you will use to conduct your proposed development and production activities.
(d)
(e)
(f)
(1) The activities and facilities proposed in your DPP or DOCD are or will be covered by an appropriate bond under 30 CFR part 256, subpart I;
(2) You have demonstrated or will demonstrate oil spill financial responsibility for facilities proposed in your DPP or DOCD, according to 30 CFR Part 253; and
(3) You have or will have the financial capability to drill a relief well and conduct other emergency well control operations.
(g)
(h)
(i)
The following G&G information must accompany your DPP or DOCD:
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
The following H
(a)
(b)
(c)
(d)
(i) Model a potential worst case H
(ii) Include a modeling report or modeling results, or a reference to such report or results if you have already submitted it to the Regional Supervisor.
(2) The analysis in the modeling report must be specific to the particular site of your development and production activities, and must consider any nearby human-occupied OCS facilities, shipping lanes, fishery areas, and other points where humans may be subject to potential exposure from an H
(3) If any H
The following mineral resource conservation information, as applicable, must accompany your DPP or DOCD:
(a)
(b)
(c)
If you obtain the following information in developing your DPP or DOCD, or if the Regional Supervisor requires you to obtain it, you must include a report, or the information obtained, or a reference to such a report or information if you have already submitted it to the Regional Supervisor, as accompanying information:
(a)
(b)
(c)
The following solid and liquid wastes and discharges information and cooling water intake information must accompany your DPP or DOCD:
(a)
(1) The methods you used for determining this information; and
(2) Your plans for treating, storing, and downhole disposal of these wastes at your facility location(s).
(b)
(1) A table showing the name, projected amount, and rate of discharge for each waste type; and
(2) A description of the discharge method (such as shunting through a downpipe, adding to a produced water stream, etc.) you will use.
(c)
(2) A copy of your application for an individual NPDES permit. Briefly describe the major discharges and methods you will use for compliance.
(d)
(e)
The following air emissions information, as applicable, must accompany your DPP or DOCD:
(a)
(1) For each source on or associated with the facility you will use to conduct your proposed development and production activities, you must list:
(i) The projected peak hourly emissions;
(ii) The total annual emissions in tons per year;
(iii) Emissions over the duration of the proposed development and production activities;
(iv) The frequency and duration of emissions; and
(v) The total of all emissions listed in paragraph (a)(1)(i) through (iv) of this section.
(2) If your proposed production and development activities would result in an increase in the emissions of an air pollutant from your facility to an amount greater than the amount specified in your previously approved DPP or DOCD, you must show the revised emission rates for each source as well as the incremental change for each source.
(3) You must provide the basis for all calculations, including engine size and rating, and applicable operational information.
(4) You must base the projected emissions on the maximum rated capacity of the equipment and the maximum throughput of the facility you will use to conduct your proposed development and production activities under its physical and operational design.
(5) If the specific drilling unit has not yet been determined, you must use the maximum emission estimates for the type of drilling unit you will use.
(b)
(c)
(d)
(e)
(f)
The following information regarding potential spills of oil (see definition under 30 CFR 254.6) and hazardous substances (see definition under 40 CFR part 116), as applicable, must accompany your DPP or DOCD:
(a)
(1) An Oil Spill Response Plan (OSRP) for the facilities you will use to conduct your proposed development and production activities prepared according to the requirements of 30 CFR part 254, subpart B; or
(2) Reference to your approved regional OSRP (see 30 CFR 254.3) to include:
(i) A discussion of your regional OSRP;
(ii) The location of your primary oil spill equipment base and staging area;
(iii) The name(s) of your oil spill removal organization(s) for both equipment and personnel;
(iv) The calculated volume of your worst case discharge scenario (see 30 CFR 254.26(a)), and a comparison of the appropriate worst case discharge scenario in your approved regional OSRP with the worst case discharge scenario that could result from your proposed development and production activities; and
(v) A description of the worst case oil spill scenario that could result from your proposed development and production activities (see 30 CFR 254.26(b), (c), (d), and (e)).
(b)
If you propose development and production activities in the Alaska OCS Region, the following planning information must accompany your DPP:
(a)
(b)
The following environmental monitoring information, as applicable, must accompany your DPP or DOCD:
(a)
(b)
(1) Threatened and endangered species listed under the ESA and
(2) Marine mammals, as appropriate, if you have not already received authorization for incidental take of marine mammals as may be necessary under the MMPA.
(c)
A description of the measures you took, or will take, to satisfy the conditions of lease stipulations related to your proposed development and production activities must accompany your DPP or DOCD.
(a) If you propose to use any measures beyond those required by the regulations in this part to minimize or mitigate environmental impacts from your proposed development and production activities, a description of the measures you will use must accompany your DPP or DOCD.
(b) If there is reason to believe that protected species may be incidentally taken by planned development and production activities, you must include mitigation measures designed to avoid or minimize that incidental take of:
(1) Threatened and endangered species listed under the ESA and
(2) Marine mammals, as appropriate, if you have not already received authorization for incidental take as may be necessary under the MMPA.
A brief description of how you intend to decommission your wells, platforms, pipelines, and other facilities, and clear your site(s) must accompany your DPP or DOCD.
The following information regarding facilities and operations directly related to your proposed development and production activities must accompany your DPP or DOCD.
(a)
(1) Drilling units;
(2) Production platforms;
(3) Right-of-way pipelines (including those that transport chemical products and produced water); and
(4) Other facilities and operations located on the OCS (regardless of ownership).
(b)
(1) Routes of any new pipelines;
(2) Information concerning barges and shuttle tankers, including the storage capacity of the transport vessel(s), and the number of transfers that will take place per year;
(3) Information concerning any intermediate storage or processing facilities;
(4) An estimate of the quantities of oil, gas, or sulphur to be transported from your production facilities; and
(5) A description and location of the primary onshore terminal.
The following information on the support vessels, offshore vehicles, and aircraft you will use must accompany your DPP or DOCD:
(a)
(b)
(c)
(d)
(e)
The following information on the onshore support facilities you will use must accompany your DPP or DOCD:
(a)
(1) Indicate whether the onshore support facilities are existing, to be constructed, or to be expanded; and
(2) For DPPs only, provide a timetable for acquiring lands (including rights-of-way and easements) and constructing or expanding any of the onshore support facilities.
(b)
(c)
(d)
If you are proposing to conduct sulphur development and production activities, the following information must accompany your DPP or DOCD:
(a)
(b)
The following CZMA information must accompany your DPP or DOCD:
(a)
(b)
The following EIA information must accompany your DPP or DOCD:
(a)
(1) Assess the potential environmental impacts of your proposed development and production activities;
(2) Be project specific; and
(3) Be as detailed as necessary to assist the Regional Supervisor in complying with the NEPA of 1969 (42 U.S.C. 4321
(b)
(1) Meteorology, oceanography, geology, and shallow geological or manmade hazards;
(2) Air and water quality;
(3) Benthic communities, marine mammals, sea turtles, coastal and marine birds, fish and shellfish, and plant life;
(4) Threatened or endangered species and their critical habitat;
(5) Sensitive biological resources or habitats such as essential fish habitat, refuges, preserves, special management areas identified in coastal management programs, sanctuaries, rookeries, and calving grounds;
(6) Archaeological resources;
(7) Socioeconomic resources (including the approximate number, timing, and duration of employment of persons engaged in onshore support and construction activities), population (including the approximate number of people and families added to local onshore areas), existing offshore and onshore infrastructure (including major sources of supplies, services, energy, and water), types of contractors or vendors that may place a demand on local goods and services, land use, subsistence resources and harvest practices, recreation, recreational and commercial fishing (including seasons, location, and type), minority and lower income groups, and CZMA programs;
(8) Coastal and marine uses such as military activities, shipping, and mineral exploration or development; and
(9) Other resources, conditions, and activities identified by the Regional Supervisor.
(c)
(1) Analyze the potential direct and indirect impacts (including those from accidents, cooling water intake structures, and those identified in relevant ESA biological opinions such as, but not limited to, those from noise, vessel collisions, and marine trash and debris) that your proposed development and production activities will have on the identified resources, conditions, and activities;
(2) Describe the type, severity, and duration of these potential impacts and their biological, physical, and other consequences and implications;
(3) Describe potential measures to minimize or mitigate these potential impacts;
(4) Describe any alternatives to your proposed development and production activities that you considered while developing your DPP or DOCD, and compare the potential environmental impacts; and
(5) Summarize the information you incorporate by reference.
(d)
(e)
The following administrative information must accompany your DPP or DOCD:
(a)
(b)
(2) The location(s) where the Regional Supervisor can inspect the cited referenced material if you have not submitted it.
(a)
(1) The submitted information, including the information that must accompany the DPP or DOCD (refer to the list in § 250.242), fulfills requirements and is sufficiently accurate;
(2) You have provided all needed additional information (see § 250.201(b)); and
(3) You have provided the required number of copies (see § 250.206(a)).
(b)
(c)
(a)
(1)
(2)
(3)
(b)
(c)
(d)
(a)
(b)
(c)
The Regional Supervisor will evaluate the environmental impacts of the activities described in your proposed DPP or DOCD and prepare environmental documentation under the National Environmental Policy Act (NEPA) (42 U.S.C.4321
(a)
(b)
(c)
(a)
(1) The Regional Supervisor will make a decision within 60 calendar days after the latest of the day that:
(i) The comment period provided in § 250.267(a)(1), (a)(2), and (b) closes;
(ii) The final EIS for a DPP is released or adopted; or
(iii) The last amendment to your proposed DOCD is received by the Regional Supervisor.
(2) Notwithstanding paragraph (a)(1) of this section, MMS will not approve your DPP or DOCD until either:
(i) All affected States with approved CZMA programs concur, or have been conclusively presumed to concur, with your DPP or DOCD consistency certification under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) and (ii)); or
(ii) The Secretary of Commerce has made a finding authorized by section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in the DPP or DOCD is consistent with the objectives of the CZMA, or is otherwise necessary in the interest of national security.
(b)
The Regional Supervisor will disapprove your proposed DPP or DOCD if one of the four reasons in this section applies:
(a)
(b)
(2) An affected State objects to your coastal zone consistency certification, and the Secretary of Commerce, under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)), has not found that each activity described in the DPP or DOCD is consistent with the objectives of the CZMA or is otherwise necessary in the interest of national security.
(3) If the Regional Supervisor disapproved your DPP or DOCD for the sole reason that an affected State either has not yet issued a final decision on, or has objected to, your coastal zone consistency certification (see paragraphs (b)(1) and (2) in this section), the Regional Supervisor will approve your DPP or DOCD upon receipt of concurrence by the affected State, at the time concurrence of the affected State is conclusively presumed, or when the Secretary of Commerce makes a finding authorized by section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(iii)) that each activity described in your DPP or DOCD is consistent with the objectives of the CZMA, or is otherwise necessary in the
(c)
(d)
(1) Implementing your DPP or DOCD would 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 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 disapproving your DPP or DOCD outweigh the advantages of development and production.
If an affected State objects to the coastal zone consistency certification accompanying your proposed or disapproved DPP or DOCD, you may do one of the following:
(a)
(b)
(1) Grant your appeal by finding under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity described in detail in your DPP or DOCD is consistent with the objectives of the CZMA, or is otherwise necessary in the interest of national security; or
(2) Deny your appeal, in which case you may amend or resubmit your DPP or DOCD, as described in paragraph (a) of this section.
(c)
(a)
(b)
(c)
(a)
(1) You may be subject to MMS enforcement action, including civil penalties; and
(2) The lease(s) involved in your EP, DPP, or DOCD may be forfeited or cancelled under 43 U.S.C. 1334(c) or (d). If this happens, you will not be entitled to compensation under § 250.185(b) and 30 CFR 256.77.
(b)
(a)
(1) Approval of applications for permits to drill (APDs) (see § 250.410);
(2) Approval of production safety systems (see § 250.800);
(3) Approval of new platforms and other structures (or major modifications to platforms and other structures) (see § 250.905);
(4) Approval of applications to install lease term pipelines (see § 250.1007); and
(5) Other permits, as required by applicable law.
(b)
(c)
(d)
(1) All affected States with approved coastal zone management programs concur, or are conclusively presumed to concur, with the coastal zone consistency certification accompanying your EP under section 307(c)(3)(B)(i) and (ii) of the CZMA (16 U.S.C. 1456(c)(3)(B)(i) and (ii)); or
(2) The Secretary of Commerce finds, under section 307(c)(3)(B)(iii) of the CZMA (16 U.S.C.1456(c)(3)(B)(iii)) that each activity covered by the EP is consistent with the objectives of the CZMA or is otherwise necessary in the interest of national security;
(3) If an affected State objects to the coastal zone consistency certification accompanying your approved EP after MMS has approved your EP, you may either:
(i) Revise your EP to accommodate the State's objection and submit the revision to the Regional Supervisor for approval; or
(ii) Appeal the State's objection to the Secretary of Commerce using the procedures in 15 CFR part 930 subpart H. The Secretary of Commerce will either:
(A) Grant your appeal by making the finding described in paragraph (d)(2) of this section; or
(B) Deny your appeal, in which case you may revise your EP as described in paragraph (d)(3)(i) of this section.
After approving your EP, DPP, or DOCD, the Regional Supervisor may direct you to conduct monitoring programs, including monitoring in accordance with the ESA and the MMPA. You must retain copies of all monitoring data obtained or derived from your monitoring programs and make them available to the MMS upon request. The Regional Supervisor may require you to:
(a)
(b)
(a)
(1) Change the type of drilling rig (e.g., jack-up, platform rig, barge, submersible, semisubmersible, or drillship), production facility (e.g., caisson, fixed platform with piles, tension leg platform), or transportation mode (e.g., pipeline, barge);
(2) Change the surface location of a well or production platform by a distance more than that specified by the Regional Supervisor;
(3) Change the type of production or significantly increase the volume of production or storage capacity;
(4) Increase the emissions of an air pollutant to an amount that exceeds the amount specified in your approved EP, DPP, or DOCD;
(5) Significantly increase the amount of solid or liquid wastes to be handled or discharged;
(6) Request a new H2S area classification, or increase the concentration of H2S to a concentration greater than that specified by the Regional Supervisor;
(7) Change the location of your onshore support base either from one State to another or to a new base or a base requiring expansion; or
(8) Change any other activity specified by the Regional Supervisor.
(b)
(a)
(b)
(a)
(b)
(c)
(a) A DWOP is a plan that provides sufficient information for MMS to review a deepwater development project, and any other project that uses non-conventional production or completion technology, from a total system approach. The DWOP does not replace, but supplements other submittals required by the regulations such as Exploration Plans, Development and Production Plans, and Development Operations Coordination Documents. MMS
(b) The DWOP process consists of two parts: a Conceptual Plan and the DWOP. Section 250.289 prescribes what the Conceptual Plan must contain, and § 250.292 prescribes what the DWOP must contain.
You must submit a DWOP for each development project in which you will use non-conventional production or completion technology, regardless of water depth. If you are unsure whether MMS considers the technology of your project non-conventional, you must contact the Regional Supervisor for guidance.
You must submit four copies, or one hard copy and one electronic version, of the Conceptual Plan to the Regional Director after you have decided on the general concept(s) for development and before you begin engineering design of the well safety control system or subsea production systems to be used after well completion.
In the Conceptual Plan, you must explain the general design basis and philosophy that you will use to develop the field. You must include the following information:
(a) An overview of the development concept(s);
(b) A well location plat;
(c) The system control type (
(d) The distance from each of the wells to the host platform.
You may not complete any production well or install the subsea wellhead and well safety control system (often called the tree) before MMS has approved the Conceptual Plan.
You must submit four copies, or one hard copy and one electronic version, of the DWOP to the Regional Director after you have substantially completed safety system design and before you begin to procure or fabricate the safety and operational systems (other than the tree), production platforms, pipelines, or other parts of the production system.
You must include the following information in your DWOP:
(a) A description and schematic of the typical wellbore, casing, and completion;
(b) Structural design, fabrication, and installation information for each surface system, including host facilities;
(c) Design, fabrication, and installation information on the mooring systems for each surface system;
(d) Information on any active stationkeeping system(s) involving thrusters or other means of propulsion used with a surface system;
(e) Information concerning the drilling and completion systems;
(f) Design and fabrication information for each riser system (e.g., drilling, workover, production, and injection);
(g) Pipeline information;
(h) Information about the design, fabrication, and operation of an offtake system for transferring produced hydrocarbons to a transport vessel;
(i) Information about subsea wells and associated systems that constitute all or part of a single project development covered by the DWOP;
(j) Flow schematics and Safety Analysis Function Evaluation (SAFE) charts (API RP 14C, subsection 4.3c, incorporated by reference in § 250.198) of the production system from the Surface Controlled Subsurface Safety Valve (SCSSV) downstream to the first item of separation equipment;
(k) A description of the surface/subsea safety system and emergency support systems to include a table that depicts what valves will close, at what times, and for what events or reasons;
(l) A general description of the operating procedures, including a table summarizing the curtailment of production and offloading based on operational considerations;
(m) A description of the facility installation and commissioning procedure;
(n) A discussion of any new technology that affects hydrocarbon recovery systems;
(o) A list of any alternate compliance procedures or departures for which you anticipate requesting approval; and
(p) Payment of the service fee listed in § 250.125.
You may not begin production until MMS approves your DWOP.
If your development project meets the following criteria, you may submit a combined Conceptual Plan/DWOP on or before the deadline for submitting the Conceptual Plan.
(a) The project is located in water depths of less than 400 meters (1,312 feet); and
(b) The project is similar to projects involving non-conventional production or completion technology for which you have obtained approval previously.
You must revise either the Conceptual Plan or your DWOP to reflect changes in your development project that materially alter the facilities, equipment, and systems described in your plan. You must submit the revision within 60 days after any material change to the information required for that part of your plan.
(a) You must submit one original and two copies of a CID to the appropriate OCS Region at the same time you first submit your DOCD or DPP for any development of a lease or leases located in water depths greater than 400 meters (1,312 feet). You must also submit a CID for a Supplemental DOCD or DPP when requested by the Regional Supervisor. The submission of your CID must be accompanied by payment of the service fee listed in § 250.125.
(b) If you decide not to develop a reservoir you committed to develop in your CID, you must submit one original and two copies of a revision to the CID to the appropriate OCS Region. The revision to the CID must be submitted within 14 calendar days after making your decision not to develop the reservoir and before the reservoir is bypassed. The Regional Supervisor will approve or disapprove any such revision to the original CID. If the Regional Supervisor disapproves the revision, you must develop the reservoir as described in the original CID.
(a) You must base the CID on wells drilled before your CID submittal, that define the extent of the reservoirs. You must notify MMS of any well that is drilled to total depth during the CID evaluation period and you may be required to update your CID.
(b) You must include all of the following information if available. Information must be provided for each hydrocarbon-bearing reservoir that is penetrated by a well that would meet the producibility requirements of § 250.115 or § 250.116:
(1) General discussion of the overall development of the reservoir;
(2) Summary spreadsheets of well log data and reservoir parameters (
(3) Appropriate well logs, including digital well log (
(4) Sidewall core/whole core and pressure-volume-temperature analysis;
(5) Structure maps, with the existing and proposed penetration points and subsea depths for all wells penetrating the reservoirs, fluid contacts (or the lowest or highest known levels in the absence of actual contacts), reservoir boundaries, and the scale of the map;
(6) Interpreted structural cross sections and corresponding interpreted seismic lines or block diagrams, as necessary, that include all current wellbores and planned wellbores on the leases or units to be developed, the reservoir boundaries, fluid contacts, depth scale, stratigraphic positions, and relative biostratigraphic ages;
(7) Isopach maps of each reservoir showing the net feet of pay for each well within the reservoir identified at the penetration point, along with the well name, labeled contours, and scale;
(8) Estimates of original oil and gas in-place and anticipated recoverable oil and gas reserves, all reservoir parameters, and risk factors and assumptions;
(9) Plat map at the same scale as the structure maps with existing and proposed well paths, as well as existing and proposed penetrations;
(10) Wellbore schematics indicating proposed perforations;
(11) Proposed wellbore utility chart showing all existing and proposed wells, with proposed completion intervals indicated for each borehole;
(12) Appropriate pressure data, specified by date, and whether estimated or measured;
(13) Description of reservoir development strategies;
(14) Description of the enhanced recovery practices you will use or, if you do not plan to use such practices, an explanation of the methods you considered and reasons you do not intend to use them;
(15) For each reservoir you do not intend to develop:
(i) A statement explaining the reason(s) you will not develop the reservoir, and
(ii) Economic justification, including costs, recoverable reserve estimate, production profiles, and pricing assumptions; and
(16) Any other appropriate data you used in performing your reservoir evaluations and preparing your reservoir development strategies.
(a) The Regional Supervisor will make a decision within 150 calendar days of receiving your CID. If MMS does not act within 150 calendar days, your CID is considered approved.
(b) MMS may suspend the 150-calendar-day evaluation period if there is missing, inconclusive, or inaccurate data, or when a well reaches total depth during the evaluation period. MMS may also suspend the evaluation period when a well penetrating a hydrocarbon-bearing structure reaches total depth during the evaluation period and the data from that well is needed for the CID. You will receive written notification from the Regional Supervisor describing the additional information that is needed, and the evaluation period will resume once MMS receives the requested information.
(c) The Regional Supervisor will approve or deny your CID request based on your commitment to develop economically producible reservoirs according to sound conservation, engineering, and economic practices.
You may not begin production before you receive MMS approval of the CID.
(a) During the exploration, development, production, and transportation of oil and gas or sulphur, the lessee shall take measures to prevent unauthorized discharge of pollutants into the offshore waters. The lessee shall not create conditions that will pose unreasonable risk to public health, life,
(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 Manager 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 Manager.
(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 Manager may restrict the rate of drilling fluid discharges or prescribe alternative discharge methods. The District Manager 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 Manager.
(2) Approval of the method of disposal of drill cuttings, sand, and other well solids shall be obtained from the District Manager.
(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
(a) Drilling and production facilities shall be inspected daily or at intervals approved or prescribed by the District Manager 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 § 250.218 or § 250.249 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 that air pollutant shall be deemed to significantly affect the air quality of the onshore area for VOC.
(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 § 250.218 or 250.249 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 longer period of time at the discretion of the Regional Supervisor. The lessee shall comply with the requirements of this section as necessary.
(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 requirements of this subpart apply to lessees, operating rights owners, operators, and their contractors and subcontractors.
You must take necessary precautions to keep wells under control at all times. You must:
(a) Use the best available and safest drilling technology to monitor and evaluate well conditions and to minimize the potential for the well to flow or kick;
(b) Have a person onsite during drilling operations who represents your interests and can fulfill your responsibilities;
(c) Ensure that the toolpusher, operator's representative, or a member of the drilling crew maintains continuous surveillance on the rig floor from the beginning of drilling operations until the well is completed or abandoned, unless you have secured the well with blowout preventers (BOPs), bridge plugs, cement plugs, or packers;
(d) Use personnel trained according to the provisions of subpart O; and
(e) Use and maintain equipment and materials necessary to ensure the safety and protection of personnel, equipment, natural resources, and the environment.
Whenever you interrupt drilling operations, you must install a downhole safety device, such as a cement plug, bridge plug, or packer. You must install the device at an appropriate depth within a properly cemented casing string or liner.
(a) Among the events that may cause you to interrupt drilling operations are:
(1) Evacuation of the drilling crew;
(2) Inability to keep the drilling rig on location; or
(3) Repair to major drilling or well-control equipment.
(b) For floating drilling operations, the District Manager may approve the use of blind or blind-shear rams or pipe rams and an inside BOP if you don't have time to install a downhole safety device or if special circumstances occur.
(a) You must report the movement of all drilling units on and off drilling locations to the District Manager. This includes both MODU and platform rigs. You must inform the District Manager 24 hours before:
(1) The arrival of an MODU on location;
(2) The movement of a platform rig to a platform;
(3) The movement of a platform rig to another slot;
(4) The movement of an MODU to another slot; and
(5) The departure of an MODU from the location.
(b) You must provide the District Manager with the rig name, lease number, well number, and expected time of arrival or departure.
(c) In the Gulf of Mexico OCS Region, you must report drilling unit movements on form MMS-144, Rig Movement Notification Report.
You must have a crown block safety device that prevents the traveling block from striking the crown block. You must check the device for proper operation at least once per week and after each drill-line slipping operation and record the results of this operational check in the driller's report.
You must equip each diesel engine with an air take device to shut down
(a) For a diesel engine that is not continuously manned, you must equip the engine with an automatic shutdown device;
(b) For a diesel engine that is continuously manned, you may equip the engine with either an automatic or remote manual air intake shutdown device;
(c) You do not have to equip a diesel engine with an air intake device if it meets one of the following criteria:
(1) Starts a larger engine;
(2) Powers a firewater pump;
(3) Powers an emergency generator;
(4) Powers a BOP accumulator system;
(5) Provides air supply to divers or confined entry personnel;
(6) Powers temporary equipment on a nonproducing platform;
(7) Powers an escape capsule; or
(8) Powers a portable single-cylinder rig washer.
You must take the following safety measures when you conduct drilling operations on a platform with producing wells or that has other hydrocarbon flow:
(a) You must install an emergency shutdown station near the driller's console;
(b) You must shut in all producible wells located in the affected wellbay below the surface and at the wellhead when:
(1) You move a drilling rig or related equipment on and off a platform. This includes rigging up and rigging down activities within 500 feet of the affected platform;
(2) You move or skid a drilling unit between wells on a platform;
(3) A mobile offshore drilling unit (MODU) moves within 500 feet of a platform. You may resume production once the MODU is in place, secured, and ready to begin drilling operations.
You must determine the presence, quantity, quality, and reservoir characteristics of oil, gas, sulphur, and water in the formations penetrated by logging, formation sampling, or well testing.
You may use alternative procedures or equipment during drilling operations after receiving approval from the District Manager. You must identify and discuss your proposed alternative procedures or equipment in your Application for Permit to Drill (APD) (Form MMS-123) (see § 250.414(h)). Procedures for obtaining approval are described in section 250.141 of this part.
The District Manager may approve departures from the drilling requirements specified in this subpart. You may apply for a departure from drilling requirements by writing to the District Manager. You should identify and discuss the departure you are requesting in your APD (see § 250.414(h)).
You must obtain written approval from the District Manager before you begin drilling any well or before you sidetrack, bypass, or deepen a well. To obtain approval, you must:
(a) Submit the information required by § 250.411 through 250.418;
(b) Include the well in your approved Exploration Plan (EP), Development and Production Plan (DPP), or Development Operations Coordination Document (DOCD);
(c) Meet the oil spill financial responsibility requirements for offshore facilities as required by 30 CFR part 253; and
(d) Submit the following to the District Manager:
(1) An original and two complete copies of Form MMS-123, Application for Permit to Drill (APD), and Form MMS-123S, Supplemental APD Information Sheet;
(2) A separate public information copy of forms MMS-123 and MMS-123S that meets the requirements of § 250.186; and
(3) Payment of the service fee listed in § 250.125.
In addition to forms MMS-123 and MMS-123S, you must include the information described in the following table.
The location plat must:
(a) Have a scale of 1:24,000 (1 inch = 2,000 feet);
(b) Show the surface and subsurface locations of the proposed well and all the wells in the vicinity;
(c) Show the surface and subsurface locations of the proposed well in feet or meters from the block line;
(d) Contain the longitude and latitude coordinates, and either Universal Transverse Mercator grid-system coordinates or state plane coordinates in the Lambert or Transverse Mercator Projection system for the surface and subsurface locations of the proposed well; and
(e) State the units and geodetic datum (including whether the datum is North American Datum 27 or 83) for these coordinates. If the datum was converted, you must state the method used for this conversion, since the various methods may produce different values.
Your description of well drilling design criteria must address:
(a) Pore pressures;
(b) Formation fracture gradients, adjusted for water depth;
(c) Potential lost circulation zones;
(d) Drilling fluid weights;
(e) Casing setting depths;
(f) Maximum anticipated surface pressures. For this section, maximum anticipated surface pressures are the pressures that you reasonably expect to be exerted upon a casing string and its related wellhead equipment. In calculating maximum anticipated surface pressures, you must consider: drilling, completion, and producing conditions; drilling fluid densities to be used below various casing strings; fracture gradients of the exposed formations; casing setting depths; total well depth; formation fluid types; safety margins; and other pertinent conditions. You must include the calculations used to determine the pressures for the drilling and the completion phases, including the anticipated surface pressure used for designing the production string;
(g) A single plot containing estimated pore pressures, formation fracture gradients, proposed drilling fluid weights, and casing setting depths in true vertical measurements;
(h) A summary report of the shallow hazards site survey that describes the geological and manmade conditions if not previously submitted; and
(i) Permafrost zones, if applicable.
Your drilling prognosis must include a brief description of the procedures
(a) Projected plans for coring at specified depths;
(b) Projected plans for logging;
(c) Planned safe drilling margin between proposed drilling fluid weights and estimated pore pressures. This safe drilling margin may be shown on the plot required by § 250.413(g);
(d) Estimated depths to the top of significant marker formations;
(e) Estimated depths to significant porous and permeable zones containing fresh water, oil, gas, or abnormally pressured formation fluids;
(f) Estimated depths to major faults;
(g) Estimated depths of permafrost, if applicable;
(h) A list and description of all requests for using alternative procedures or departures from the requirements of this subpart in one place in the APD. You must explain how the alternative procedures afford an equal or greater degree of protection, safety, or performance, or why you need the departures; and
(i) Projected plans for well testing (refer to § 250.460 for safety requirements).
Your casing and cementing programs must include:
(a) Hole sizes and casing sizes, including: weights; grades; collapse, and burst values; types of connection; and setting depths (measured and true vertical depth (TVD));
(b) Casing design safety factors for tension, collapse, and burst with the assumptions made to arrive at these values;
(c) Type and amount of cement (in cubic feet) planned for each casing string;
(d) In areas containing permafrost, setting depths for conductor and surface casing based on the anticipated depth of the permafrost. Your program must provide protection from thaw subsidence and freezeback effect, proper anchorage, and well control;
(e) A statement of how you evaluated the best practices included in API RP 65, Recommended Practice for Cementing Shallow Water Flow Zones in Deep Water Wells (incorporated by reference as specified in § 250.198), if you drill a well in water depths greater than 500 feet and are in either of the following two areas:
(1) An “area with an unknown shallow water flow potential” is a zone or geologic formation where neither the presence nor absence of potential for a shallow water flow has been confirmed.
(2) An “area known to contain a shallow water flow hazard” is a zone or geologic formation for which drilling has confirmed the presence of shallow water flow; and
(f) A written description of how you evaluated the best practices included in API RP 65-Part 2, Isolating Potential Flow Zones During Well Construction (incorporated by reference as specified in § 250.198). Your written description must identify the mechanical barriers and cementing practices you will use for each casing string (reference API RP 65-Part 2, Sections 3 and 4).
You must include in the diverter and BOP descriptions:
(a) A description of the diverter system and its operating procedures;
(b) A schematic drawing of the diverter system (plan and elevation views) that shows:
(1) The size of the annular BOP installed in the diverter housing;
(2) Spool outlet internal diameter(s);
(3) Diverter-line lengths and diameters; burst strengths and radius of curvature at each turn; and
(4) Valve type, size, working pressure rating, and location;
(c) A description of the BOP system and system components, including pressure ratings of BOP equipment and proposed BOP test pressures;
(d) A schematic drawing of the BOP system that shows the inside diameter of the BOP stack, number and type of preventers, all control systems and pods, location of choke and kill lines, and associated valves;
(e) Independent third party verification and supporting documentation that show the blind-shear rams installed in the BOP stack are capable of shearing any drill pipe in the hole under maximum anticipated surface pressure. The documentation must include test results and calculations of shearing capacity of all pipe to be used in the well including correction for MASP;
(f) When you use a subsea BOP stack, independent third party verification that shows:
(1) the BOP stack is designed for the specific equipment on the rig and for the specific well design;
(2) The BOP stack has not been compromised or damaged from previous service;
(3) The BOP stack will operate in the conditions in which it will be used; and
(g) The qualifications of the independent third party referenced in paragraphs (e) and (f) of this section:
(1) The independent third party in paragraph (e) in this section must be a technical classification society; an API-licensed manufacturing, inspection, or certification firm; or a licensed professional engineering firm capable of providing the verifications required under this part. The independent third party must not be the original equipment manufacturer (OEM).
(2) You must:
(i) Include evidence that the firm you are using is reputable, the firm or its employees hold appropriate licenses to perform the verification in the appropriate jurisdiction, the firm carries industry-standard levels of professional liability insurance, and the firm has no record of violations of applicable law.
(ii) Ensure that an official representative of BOEMRE will have access to the location to witness any testing or inspections, and verify information submitted to BOEMRE. Prior to any shearing ram tests or inspections, you must notify the District Manager at least 24 hours in advance.
If you plan to use a MODU, you must provide:
(a)
(b)
(c)
(2) If you plan to drill in a frontier area, you must have a contingency plan that addresses design and operating limitations of the drilling unit. Your plan must identify the actions
(d)
(e)
(f)
(g) Once the District Manager has approved a MODU for use, you do not need to re-submit the information required by this section for another APD to use the same MODU unless changes in equipment affect its rated capacity to operate in the District.
You must include the following with the APD:
(a) Rated capacities of the drilling rig and major drilling equipment, if not already on file with the appropriate District office;
(b) A drilling fluids program that includes the minimum quantities of drilling fluids and drilling fluid materials, including weight materials, to be kept at the site;
(c) A proposed directional plot if the well is to be directionally drilled;
(d) A Hydrogen Sulfide Contingency Plan (see § 250.490), if applicable, and not previously submitted;
(e) A welding plan (see §§ 250.109 to 250.113) if not previously submitted;
(f) In areas subject to subfreezing conditions, evidence that the drilling equipment, BOP systems and components, diverter systems, and other associated equipment and materials are suitable for operating under such conditions;
(g) A request for approval if you plan to wash out or displace some cement to facilitate casing removal upon well abandonment;
(h) Certification of your casing and cementing program as required in § 250.420(a)(6);
(i) Description of qualifications required by § 250.416(f) of any independent third party; and
(j) Such other information as the District Manager may require.
You must case and cement all wells. Your casing and cementing programs must meet the requirements of this section and of §§ 250.421 through 250.428.
(a)
(1) Properly control formation pressures and fluids;
(2) Prevent the direct or indirect release of fluids from any stratum through the wellbore into offshore waters;
(3) Prevent communication between separate hydrocarbon-bearing strata;
(4) Protect freshwater aquifers from contamination;
(5) Support unconsolidated sediments; and
(6) Include certification signed by a Registered Professional Engineer that there will be at least two independent tested barriers, including one mechanical barrier, across each flow path during well completion activities and that the casing and cementing design is appropriate for the purpose for which it is intended under expected wellbore conditions. The Registered Professional Engineer must be registered in a State in the United States. Submit this certification with your APD (Form MMS-123).
(b)
(2) The casing design must include safety measures that ensure well control during drilling and safe operations during the life of the well.
(3) For the final casing string (or liner if it is your final string), you must install dual mechanical barriers in addition to cement, to prevent flow in the event of a failure in the cement. These may include dual float valves, or one float valve and a mechanical barrier. You must submit documentation to BOEMRE 30 days after installation of the dual mechanical barriers.
(c)
The table in this section identifies specific design, setting, and cementing requirements for casing strings and liners. For the purposes of subpart D, the casing strings in order of normal installation are as follows: drive or structural, conductor, surface, intermediate, and production casings (including liners). The District Manager may approve or prescribe other casing and cementing requirements where appropriate.
(a) After cementing surface, intermediate, or production casing (or liners), you may resume drilling after the cement has been held under pressure for 12 hours. For conductor casing, you may resume drilling after the cement has been held under pressure for 8 hours. One acceptable method of holding cement under pressure is to use float valves to hold the cement in place.
(b) If you plan to nipple down your diverter or BOP stack during the 8- or 12-hour waiting time, you must determine, before nippling down, when it will be safe to do so. You must base your determination on a knowledge of formation conditions, cement composition, effects of nippling down, presence of potential drilling hazards, well conditions during drilling, cementing, and post cementing, as well as past experience.
(a) The table in this section describes the minimum test pressures for each string of casing. You may not resume drilling or other down-hole operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test, or if there is another indication of a leak, you must re-cement, repair the casing, or run additional casing to provide a proper seal. The District Manager may approve or require other casing test pressures.
(b) You must ensure proper installation of casing or liner in the subsea wellhead or liner hanger.
(1) You must ensure that the latching mechanisms or lock down mechanisms are engaged upon installation of each casing string or liner.
(2) You must perform a pressure test on the casing seal assembly to ensure proper installation of casing or liner. You must perform this test for the intermediate and production casing strings or liner.
(3) You must submit for approval with your APD, test procedures and criteria for a successful test.
(4) You must document all your test results and make them available to BOEMRE upon request.
(c) You must perform a negative pressure test on all wells to ensure proper casing installation. You must perform this test for the intermediate and production casing strings.
(1) You must submit for approval with your APD, test procedures and criteria for a successful test.
(2) You must document all your test results and make them available to BOEMRE upon request.
If wellbore operations continue for more than 30 days within a casing string run to the surface:
(a) You must stop drilling operations as soon as practicable, and evaluate the effects of the prolonged operations on continued drilling operations and
(1) Caliper or pressure test the casing; and
(2) Report the results of your evaluation to the District Manager and obtain approval of those results before resuming operations.
(b) If casing integrity has deteriorated to a level below minimum safety factors, you must:
(1) Repair the casing or run another casing string; and
(2) Obtain approval from the District Manager before you begin repairs.
(a) You must test each drilling liner (and liner-lap) to a pressure at least equal to the anticipated pressure to which the liner will be subjected during the formation pressure-integrity test below that liner shoe, or subsequent liner shoes if set. The District Manager may approve or require other liner test pressures.
(b) You must test each production liner (and liner-lap) to a minimum of 500 psi above the formation fracture pressure at the casing shoe into which the liner is lapped.
(c) You may not resume drilling or other down-hole operations until you obtain a satisfactory pressure test. If the pressure declines more than 10 percent in a 30-minute test or if there is another indication of a leak, you must re-cement, repair the liner, or run additional casing/liner to provide a proper seal.
You must record the time, date, and results of each pressure test in the driller's report maintained under standard industry practice. In addition, you must record each test on a pressure chart and have your onsite representative sign and date the test as being correct.
You must conduct a pressure integrity test below the surface casing or liner and all intermediate casings or liners. The District Manager may require you to run a pressure-integrity test at the conductor casing shoe if warranted by local geologic conditions or the planned casing setting depth. You must conduct each pressure integrity test after drilling at least 10 feet but no more than 50 feet of new hole below the casing shoe. You must test to either the formation leak-off pressure or to an equivalent drilling fluid weight if identified in an approved APD.
(a) You must use the pressure integrity test and related hole-behavior observations, such as pore-pressure test results, gas-cut drilling fluid, and well kicks to adjust the drilling fluid program and the setting depth of the next casing string. You must record all test results and hole-behavior observations made during the course of drilling related to formation integrity and pore pressure in the driller's report.
(b) While drilling, you must maintain the safe drilling margin identified in the approved APD. When you cannot maintain this safe margin, you must suspend drilling operations and remedy the situation.
The table in this section describes actions that lessees must take when certain situations occur during casing and cementing activities.
You must install a diverter system before you drill a conductor or surface hole. The diverter system consists of a diverter sealing element, diverter lines, and control systems. You must design, install, use, maintain, and test the diverter system to ensure proper diversion of gases, water, drilling fluid, and other materials away from facilities and personnel.
You must design and install your diverter system to:
(a) Use diverter spool outlets and diverter lines that have a nominal diameter of at least 10 inches for surface wellhead configurations and at least 12 inches for floating drilling operations;
(b) Use dual diverter lines arranged to provide for downwind diversion capability;
(c) Use at least two diverter control stations. One station must be on the drilling floor. The other station must be in a readily accessible location away from the drilling floor;
(d) Use only remote-controlled valves in the diverter lines. All valves in the diverter system must be full-opening. You may not install manual or butterfly valves in any part of the diverter system;
(e) Minimize the number of turns (only one 90-degree turn allowed for each line for bottom-founded drilling units) in the diverter lines, maximize the radius of curvature of turns, and target all right angles and sharp turns;
(f) Anchor and support the entire diverter system to prevent whipping and vibration; and
(g) Protect all diverter-control instruments and lines from possible damage by thrown or falling objects.
The table below describes possible departures from the diverter requirements and the conditions required for each departure. To obtain one of these departures, you must have discussed the departure in your APD and received approval from the District Manager.
When you install the diverter system, you must actuate the diverter sealing element, diverter valves, and diverter-control systems and control stations. You must also flow-test the vent lines.
(a) For drilling operations with a surface wellhead configuration, you must actuate the diverter system at least once every 24-hour period after the initial test. After you have nippled up on conductor casing, you must pressure-test the diverter-sealing element and diverter valves to a minimum of 200 psi. While the diverter is installed, you must conduct subsequent pressure tests within 7 days after the previous test.
(b) For floating drilling operations with a subsea BOP stack, you must actuate the diverter system within 7 days after the previous actuation.
(c) You must alternate actuations and tests between control stations.
You must record the time, date, and results of all diverter actuations and tests in the driller's report. In addition, you must:
(a) Record the diverter pressure test on a pressure chart;
(b) Require your onsite representative to sign and date the pressure test chart;
(c) Identify the control station used during the test or actuation;
(d) Identify problems or irregularities observed during the testing or actuations and record actions taken to remedy the problems or irregularities; and
(e) Retain all pressure charts and reports pertaining to the diverter tests and actuations at the facility for the duration of drilling the well.
You must design, install, maintain, test, and use the BOP system and system components to ensure well control. The working-pressure rating of each BOP component must exceed maximum anticipated surface pressures. The BOP system includes the BOP stack and associated BOP systems and equipment.
(a) When you drill with a surface BOP stack, you must install the BOP system before drilling below surface casing. The surface BOP stack must include at least four remote-controlled, hydraulically operated BOPs, consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped with blind or blind-shear rams.
(b) Your surface BOP stack must include at least four remote-controlled, hydraulically operated BOPs consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped with blind-shear rams. The blind-shear rams must be capable of shearing the drill pipe that is in the hole.
(c) You must install an accumulator system that provides 1.5 times the volume of fluid capacity necessary to close and hold closed all BOP components. The system must perform with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system. If you supply the accumulator regulators by rig air and do not have a secondary source of pneumatic supply, you must equip the regulators with manual overrides or other devices to ensure capability of hydraulic operations if rig air is lost.
(d) In addition to the stack and accumulator system, you must install the associated BOP systems and equipment required by the regulations in this subpart.
When you drill with a subsea BOP system, you must install the BOP system before drilling below the surface casing. The District Manager may require you to install a subsea BOP system before drilling below the conductor casing if proposed casing setting depths or local geology indicate the need. The table in this paragraph outlines your requirements.
All BOP systems must include the following associated systems and related equipment:
(a) An automatic backup to the primary accumulator-charging system. The power source must be independent from the power source for the primary accumulator-charging system. The independent power source must possess sufficient capability to close and hold closed all BOP components.
(b) At least two BOP control stations. One station must be on the drilling floor. You must locate the other station in a readily accessible location away from the drilling floor.
(c) Side outlets on the BOP stack for separate kill and choke lines. If your stack does not have side outlets, you must install a drilling spool with side outlets.
(d) A choke and a kill line on the BOP stack. You must equip each line with two full-opening valves, one of which must be remote-controlled. For a subsea BOP system, both valves in each line must be remote-controlled. In addition:
(1) You must install the choke line above the bottom ram;
(2) You may install the kill line below the bottom ram; and
(3) For a surface BOP system, on the kill line you may install a check valve and a manual valve instead of the remote-controlled valve. To use this configuration, both manual valves must be readily accessible and you must install the check valve between the manual valves and the pump.
(e) A fill-up line above the uppermost BOP.
(f) Locking devices installed on the ram-type BOPs.
(g) A wellhead assembly with a rated working pressure that exceeds the maximum anticipated surface pressure.
(a) Your BOP system must include a choke manifold that is suitable for the anticipated surface pressures, anticipated methods of well control, the surrounding environment, and the corrosiveness, volume, and abrasiveness of drilling fluids and well fluids that you may encounter.
(b) Choke manifold components must have a rated working pressure at least as great as the rated working pressure of the ram BOPs. If your choke manifold has buffer tanks downstream of choke assemblies, you must install isolation valves on any bleed lines.
(c) Valves, pipes, flexible steel hoses, and other fittings upstream of the choke manifold must have a rated working pressure at least as great as the rated working pressure of the ram BOPs.
You must use or provide the following BOP equipment during drilling operations:
(a) A kelly valve installed below the swivel (upper kelly valve);
(b) A kelly valve installed at the bottom of the kelly (lower kelly valve). You must be able to strip the lower kelly valve through the BOP stack;
(c) If you drill with a mud motor and use drill pipe instead of a kelly, you must install one kelly valve above, and one strippable kelly valve below, the joint of drill pipe used in place of a kelly;
(d) On a top-drive system equipped with a remote-controlled valve, you must install a strippable kelly-type valve below the remote-controlled valve;
(e) An inside BOP in the open position located on the rig floor. You must
(f) A drill-string safety valve in the open position located on the rig floor. You must have a drill-string safety valve available for each size connection in the drill string;
(g) When running casing, you must have a safety valve in the open position available on the rig floor to fit the casing string being run in the hole;
(h) All required manual and remote-controlled kelly valves, drill-string safety valves, and comparable-type valves (
(i) The drilling crew must have ready access to a wrench to fit each manual valve.
(a) You must maintain and inspect your BOP system to ensure that the equipment functions properly. The BOP maintenance and inspections must meet or exceed the provisions of Sections 17.10 and 18.10, Inspections; Sections 17.11 and 18.11, Maintenance; and Sections 17.12 and 18.12, Quality Management, described in API RP 53, Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells (incorporated by reference as specified in § 250.198). You must document the procedures used, record the results of your BOP inspections and maintenance actions, and make available to BOEMRE upon request. You must maintain your records on the rig for 2 years or from the date of your last major inspection, whichever is longer;
(b) You must visually inspect your surface BOP system on a daily basis. You must visually inspect your subsea BOP system and marine riser at least once every 3 days if weather and sea conditions permit. You may use television cameras to inspect subsea equipment.
You must pressure test your BOP system (this includes the choke manifold, kelly valves, inside BOP, and drill-string safety valve):
(a) When installed;
(b) Before 14 days have elapsed since your last BOP pressure test. You must begin to test your BOP system before midnight on the 14th day following the conclusion of the previous test. However, the District Manager may require more frequent testing if conditions or BOP performance warrant; and
(c) Before drilling out each string of casing or a liner. The District Manager may allow you to omit this test if you didn't 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 APD which casing strings and liners meet these criteria.
When you pressure test the BOP system, you must conduct a low-pressure and a high-pressure test for each BOP component. You must conduct the low-pressure test before the high-pressure test. Each individual pressure test must hold pressure long enough to demonstrate that the tested component(s) holds the required pressure. Required test pressures are as follows:
(a)
(b)
(c)
(d)
You must meet the following additional BOP testing requirements:
(a) Use water to test a surface BOP system;
(b) Stump test a subsea BOP system before installation. You must use water to conduct this test. You may use drilling fluids to conduct subsequent tests of a subsea BOP system;
(c) Alternate tests between control stations and pods;
(d) Pressure test the blind or blind-shear ram BOP during stump tests and at all casing points;
(e) The interval between any blind or blind-shear ram BOP pressure tests may not exceed 30 days;
(f) Pressure test variable bore-pipe ram BOPs against the largest and smallest sizes of pipe in use, excluding drill collars and bottom-hole tools;
(g) Pressure test affected BOP components following the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack assembly;
(h) Function test annular and ram BOPs every 7 days between pressure tests;
(i) Actuate safety valves assembled with proper casing connections before running casing;
(j) Test all ROV intervention functions on your subsea BOP stack during the stump test. You must also test at least one set of rams during the initial test on the seafloor. You must submit test procedures with your APD or APM for District Manager approval. You must:
(1) ensure that the ROV hot stabs are function tested and are capable of actuating, at a minimum, one set of pipe rams and one set of blind-shear rams and unlatching the LMRP; and
(2) document all your test results and make them available to BOEMRE upon request;
(k) Function test autoshear and deadman systems on your subsea BOP stack during the stump test. You must also test the deadman system during the initial test on the seafloor.
(1) You must submit test procedures with your APD or APM for District Manager approval.
(2) You must document all your test results and make them available to BOEMRE upon request.
You must record the time, date, and results of all pressure tests, actuations, and inspections of the BOP system, system components, and marine riser in the driller's report. In addition, you must:
(a) Record BOP test pressures on pressure charts;
(b) Require your onsite representative to sign and date BOP test charts and reports as correct;
(c) Document the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. For subsea BOP systems, you must also record the closing times for annular and ram BOPs. You may reference a BOP test plan if it is available at the facility;
(d) Identify the control station and pod used during the test;
(e) Identify any problems or irregularities observed during BOP system testing and record actions taken to remedy the problems or irregularities; and
(f) Retain all records, including pressure charts, driller's report, and referenced documents pertaining to BOP
The table in this section describes actions that lessees must take when certain situations occur with BOP systems during drilling activities.
You must design and implement your drilling fluid program to prevent the loss of well control. This program must address drilling fluid safe practices, testing and monitoring equipment, drilling fluid quantities, and drilling fluid-handling areas.
Your drilling fluid program must include the following safe practices:
(a) Before starting out of the hole with drill pipe, you must properly condition the drilling fluid. You must circulate a volume of drilling fluid equal to the annular volume with the drill pipe just off-bottom. You may omit this practice if documentation in the driller's report shows:
(1) No indication of formation fluid influx before starting to pull the drill pipe from the hole;
(2) The weight of returning drilling fluid is within 0.2 pounds per gallon (1.5 pounds per cubic foot) of the drilling fluid entering the hole; and
(3) Other drilling fluid properties are within the limits established by the program approved in the APD.
(b) Record each time you circulate drilling fluid in the hole in the driller's report;
(c) When coming out of the hole with drill pipe, you must fill the annulus with drilling fluid before the hydrostatic pressure decreases by 75 psi, or every five stands of drill pipe, whichever gives a lower decrease in hydrostatic pressure. You must calculate the number of stands of drill pipe and drill collars that you may pull before you must fill the hole. You must also calculate the equivalent drilling fluid volume needed to fill the hole. Both sets of numbers must be posted near the driller's station. You must use a mechanical, volumetric, or electronic device to measure the drilling fluid required to fill the hole;
(d) You must run and pull drill pipe and downhole tools at controlled rates so you do not swab or surge the well;
(e) When there is an indication of swabbing or influx of formation fluids, you must take appropriate measures to control the well. You must circulate and condition the well, on or near-bottom, unless well or drilling-fluid conditions prevent running the drill pipe back to the bottom;
(f) You must calculate and post near the driller's console the maximum pressures that you may safely contain under a shut-in BOP for each casing string. The pressures posted must consider the surface pressure at which the formation at the shoe would break down, the rated working pressure of the BOP stack, and 70 percent of casing burst (or casing test as approved by the District Manager). As a minimum, you must post the following two pressures:
(1) The surface pressure at which the shoe would break down. This calculation must consider the current drilling fluid weight in the hole; and
(2) The lesser of the BOP's rated working pressure or 70 percent of casing-burst pressure (or casing test otherwise approved by the District Manager);
(g) You must install an operable drilling fluid-gas separator and degasser before you begin drilling operations. You must maintain this equipment throughout the drilling of the well;
(h) Before pulling drill-stem test tools from the hole, you must circulate or reverse-circulate the test fluids in the hole. If circulating out test fluids is not feasible, you may bullhead test fluids out of the drill-stem test string and tools with an appropriate kill weight fluid;
(i) When circulating, you must test the drilling fluid at least once each tour, or more frequently if conditions warrant. Your tests must conform to industry-accepted practices and include density, viscosity, and gel strength; hydrogenion concentration; filtration; and any other tests the District Manager requires for monitoring and maintaining drilling fluid quality, prevention of downhole equipment problems and for kick detection. You must record the results of these tests in the drilling fluid report;
(j) Before displacing kill-weight drilling fluid from the wellbore, you must obtain prior approval from the District Manager. To obtain approval, you must submit with your APD or APM your reasons for displacing the kill-weight drilling fluid and provide detailed step-by-step written procedures describing how you will safely displace these fluids. The step-by-step displacement procedures must address the following:
(1) Number and type of independent barriers that are in place for each flow path,
(2) Tests you will conduct to ensure integrity of independent barriers,
(3) BOP procedures you will use while displacing kill weight fluids, and
(4) Procedures you will use to monitor fluids entering and leaving the wellbore; and
(k) In areas where permafrost and/or hydrate zones are present or may be present, you must control drilling fluid temperatures to drill safely through those zones.
Once you establish drilling fluid returns, you must install and maintain the following drilling fluid-system monitoring equipment throughout subsequent drilling operations. This equipment must have the following indicators on the rig floor:
(a) Pit level indicator to determine drilling fluid-pit volume gains and losses. This indicator must include both a visual and an audible warning device;
(b) Volume measuring device to accurately determine drilling fluid volumes required to fill the hole on trips;
(c) Return indicator devices that indicate the relationship between drilling fluid-return flow rate and pump discharge rate. This indicator must include both a visual and an audible warning device; and
(d) Gas-detecting equipment to monitor the drilling fluid returns. The indicator may be located in the drilling fluid-logging compartment or on the rig floor. If the indicators are only in the logging compartment, you must continually man the equipment and
(a) You must use, maintain, and replenish quantities of drilling fluid and drilling fluid materials at the drill site as necessary to ensure well control. You must determine those quantities based on known or anticipated drilling conditions, rig storage capacity, weather conditions, and estimated time for delivery.
(b) You must record the daily inventories of drilling fluid and drilling fluid materials, including weight materials and additives in the drilling fluid report.
(c) If you do not have sufficient quantities of drilling fluid and drilling fluid material to maintain well control, you must suspend drilling operations.
You must classify drilling fluid-handling 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 (incorporated by reference as specified in § 250.198); or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities, Classified as Class 1, Zone 0, Zone 1, and Zone 2 (incorporated by reference as specified in § 250.198). In areas where dangerous concentrations of combustible gas may accumulate, you must install and maintain a ventilation system and gas monitors. Drilling fluid-handling areas must have the following safety equipment:
(a) A ventilation system 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. In addition:
(1) If natural means provide adequate ventilation, then a mechanical ventilation system is not necessary;
(2) If a mechanical system does not run continuously, then it must activate when gas detectors indicate the presence of 1 percent or more of combustible gas by volume; and
(3) If discharges from a mechanical ventilation system may be hazardous, then you must maintain the drilling fluid-handling area at a negative pressure. You must protect the negative pressure area by using at least one of the following: a pressure-sensitive alarm, open-door alarms on each access to the area, automatic door-closing devices, air locks, or other devices approved by the District Manager;
(b) Gas detectors and alarms except in open areas where adequate ventilation is provided by natural means. You must test and recalibrate gas detectors quarterly. No more than 90 days may elapse between tests;
(c) Explosion-proof or pressurized electrical equipment to prevent the ignition of explosive gases. Where you use air for pressuring equipment, you must locate the air intake outside of and as far as practicable from hazardous areas; and
(d) Alarms that activate when the mechanical ventilation system fails.
(a) If you intend to conduct a well test, you must include your projected plans for the test with your APD (form MMS-123) or in an Application for Permit to Modify (APM) (form MMS-124). Your plans must include at least the following information:
(1) Estimated flowing and shut-in tubing pressures;
(2) Estimated flow rates and cumulative volumes;
(3) Time duration of flow, buildup, and drawdown periods;
(4) Description and rating of surface and subsurface test equipment;
(5) Schematic drawing, showing the layout of test equipment;
(6) Description of safety equipment, including gas detectors and fire-fighting equipment;
(7) Proposed methods to handle or transport produced fluids; and
(8) Description of the test procedures.
(b) You must give the District Manager at least 24-hours notice before starting a well test.
For this subpart, MMS classifies a well as vertical if the calculated average of inclination readings does not exceed 3 degrees from the vertical.
(a)
(2) You must also conduct a directional survey that provides both inclination and azimuth, and digitally record the results in electronic format:
(i) Within 500 feet of setting surface or intermediate casing;
(ii) Within 500 feet of setting any liner; and
(iii) When you reach total depth.
(b)
(c)
(d)
(2) You must correct all surveys to Universal-Transverse-Mercator-Grid-north or Lambert-Grid-north after making the magnetic-to-true-north correction. Surveys must show the magnetic and grid corrections used and include a listing of the directionally computed inclinations and azimuths.
(e) If you drill within 500 feet of an adjacent lease, the Regional Supervisor may require you to furnish a copy of the well's directional survey to the affected leaseholder. This could occur when the adjoining leaseholder requests a copy of the survey for the protection of correlative rights.
You must conduct a weekly well-control drill with each drilling crew. Your drill must familiarize the crew with its roles and functions so that all crew members can perform their duties promptly and efficiently.
(a)
(b)
(c)
(1) The time to be ready to close the diverter or BOP system; and
(2) The total time to complete the entire drill.
(d)
(a) The District Manager may establish field drilling rules different from
(b) You may request the District Manager to establish, amend, or cancel field drilling rules.
(a) You must submit an APM (form MMS-124) or an End of Operations Report (form MMS-125) and other materials to the Regional Supervisor as shown in the following table. You must also submit a public information copy of each form.
(b) If you intend to perform any of the actions specified in paragraph (a)(1) of this section, you must meet the following additional requirements:
(1) Your APM (Form MMS-124) must contain a detailed statement of the proposed work that would materially change from the approved APD. The submission of your APM must be accompanied by payment of the service fee listed in § 250.125;
(2) Your form MMS-124 must include the present status of the well, depth of all casing strings set to date, well depth, present production zones and productive capability, and all other information specified; and
(3) Within 30 days after completing this work, you must submit form MMS-124 with detailed information about the work to the District Manager, unless you have already provided sufficient information in a Well Activity Report, form MMS-133 (§ 250.468(b)).
You must keep complete, legible, and accurate records for each well. You must keep drilling records onsite while drilling activities continue. After completion of drilling activities, you must keep all drilling and other well records for the time periods shown in § 250.467. You may keep these records at a location of your choice. The records must contain complete information on all of the following:
(a) Well operations;
(b) Descriptions of formations penetrated;
(c) Content and character of oil, gas, water, and other mineral deposits in each formation;
(d) Kind, weight, size, grade, and setting depth of casing;
(e) All well logs and surveys run in the wellbore;
(f) Any significant malfunction or problem; and
(g) All other information required by the District Manager in the interests of resource evaluation, waste prevention, conservation of natural resources, and
You must keep records for the time periods shown in the following table.
(a) You must submit copies of logs or charts of electrical, radioactive, sonic, and other well-logging operations; directional and vertical-well surveys; velocity profiles and surveys; and analysis of cores to MMS. Each Region will provide specific instructions for submitting well logs and surveys.
(b) For drilling operations in the GOM OCS Region, you must submit form MMS-133, Well Activity Report, to the District Manager on a weekly basis.
(c) For drilling operations in the Pacific or Alaska OCS Regions, you must submit form MMS-133, Well Activity Report, to the District Manager on a daily basis.
The District Manager or Regional Supervisor may require you to submit copies of any or all of the following well records.
(a) Well records as specified in § 250.466;
(b) Paleontological interpretations or reports identifying microscopic fossils by depth and/or washed samples of drill cuttings that you normally maintain for paleontological determinations. The Regional Supervisor may issue a Notice to Lessees that prescribes the manner, timeframe, and format for submitting this information;
(c) Service company reports on cementing, perforating, acidizing, testing, or other similar services; or
(d) Other reports and records of operations.
(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 (
(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)
(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)
(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, American National Standard for Respiratory Protection (incorporated by reference as specified in § 250.198);
(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)
(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 Manager may require additional sensors or other monitoring capabilities, if warranted by site specific conditions.
(6)
(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)
(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 Manager may require that H
(8)
(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 in conformance with ANSI Z88.2 (incorporated by reference as specified in § 250.198).
(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 Manager 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, well-completion or well-workover operations, or any combination of them), provide a system of breathing-air manifolds, hoses, and masks at the facility and the briefing areas. You must provide a cascade air-bottle system for the breathing-air manifolds to refill individual protective-breathing apparatus bottles. The cascade air-bottle system may be recharged by a high-pressure compressor suitable for providing breathing-quality air, provided the compressor suction is located in an uncontaminated atmosphere.
(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 Manager. 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 Manager 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
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.
Diesel engine air intakes must be equipped with a device to shut down the diesel engine in the event of runaway. Diesel engines that are continuously attended must be equipped with either remote operated manual or automatic-shutdown devices. Diesel engines that are not continuously attended must be equipped with automatic-shutdown devices.
All units being used for well-completion operations that have both a traveling block and a crown block must be equipped with a safety device that is designed to prevent the traveling block from striking the crown block. The device must be checked for proper operation weekly and after each drill-line slipping operation. The results of the operational check must be entered in the operations log.
When geological and engineering information available in a field enables the District Manager to determine specific operating requirements, field well-completion rules may be established on the District Manager'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 Manager or upon the request of a lessee.
(a) No well-completion operation may begin until the lessee receives written approval from the District Manager. If completion is planned and the data are available at the time you submit the Application for Permit to Drill and Supplemental APD Information Sheet (Forms MMS-123 and MMS-123S), you may request approval for a well-completion on those forms (see §§ 250.410 through 250.418 of this part). If the District Manager has not approved the completion or if the completion objective or plans have significantly changed, you must submit an Application for Permit to Modify (Form MMS-124) for approval of such operations.
(b) You must submit the following with Form MMS-124 (or with Form MMS-123; Form MMS-123S):
(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;
(4) When the well-completion is in a zone known to contain H
(5) Payment of the service fee listed in § 250.125.
(c) Within 30 days after completion, you must submit to the District Manager an End of Operations Report (Form MMS-125), including a schematic of the tubing and subsurface equipment.
(d) You must submit public information copies of Form MMS-125 according to § 250.186.
(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 must meet the appropriate standards from the following table:
(c) The BOP systems for well completions must 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. Accumulator regulators supplied by rig air and without a secondary source of pneumatic supply, must 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.
(e) The subsea BOP system for well-completions must meet the requirements in § 250.442 of this part.
(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 Manager 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
(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;
(7) Test affected BOP components following the disconnection or repair of any well-pressure containment seal in the wellhead or BOP stack assembly;
(8) Test all ROV intervention functions on your subsea BOP stack during the stump test. You must also test at least one set of rams during the initial test on the seafloor. You must submit test procedures with your APM for District Manager approval. You must:
(i) Ensure that the ROV hot stabs are function tested and are capable of actuating, at a minimum, one set of pipe rams and one set of blind-shear rams and unlatching the LMRP;
(ii) Document all your test results and make them available to BOEMRE upon request; and
(9) Function test autoshear and deadman systems on your subsea BOP stack during the stump test. You must also test the deadman system during the initial test on the seafloor.
(i) You must submit test procedures with your APM for District Manager approval.
(ii) You must document all your test results and make them available to BOEMRE upon request.
(e)
(f)
(g)
(2) You must visually inspect your BOP system and marine riser at least once each day if weather and sea conditions permit. You may use television cameras to inspect this equipment. The District Manager may approve alternate methods and frequencies to inspect a marine riser.
(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 Manager.
(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 Manager.
(c) When the tree is installed, you must equip wells to monitor for casing pressure according to the following chart:
(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.
Once you install your wellhead, you must meet the casing pressure management requirements of API RP 90 (incorporated by reference as specified in § 250.198) and the requirements of §§ 250.519 through 250.530. If there is a conflict between API RP 90 and the casing pressure requirements of this subpart, you must follow the requirements of this subpart.
You must monitor for casing pressure in your well according to the following table:
(a) You must perform a casing diagnostic test within 30 days after first observing or imposing casing pressure according to the following table:
(b) You are exempt from performing a diagnostic pressure test for the production casing on a well operating under active gas lift.
A newly completed or recompleted well often has thermal casing pressure during initial startup. Bleeding casing pressure during the startup process is considered a normal and necessary operation to manage thermal casing pressure; therefore, you do not need to evaluate these operations as a casing diagnostic test. After 30 days of continuous production, the initial production startup operation is complete and you must perform casing diagnostic testing as required in §§ 250.520 and 250.522.
Casing diagnostic testing must be repeated according to the following table:
Records of casing pressure and diagnostic tests must be kept at the field office nearest the well for a minimum of 2 years. The last casing diagnostic test for each casing or riser must be retained at the field office nearest the well until the well is abandoned.
You must take action if you have any of the following conditions:
(a) Any fixed platform well with a casing pressure exceeding its maximum allowable wellhead operating pressure (MAWOP);
(b) Any fixed platform well with a casing pressure that is greater than 100 psig and that cannot bleed to 0 psig through a
(c) Any well that has demonstrated tubing/casing, tubing/riser, casing/casing, riser/casing, or riser/riser communication;
(d) Any well that has sustained casing pressure (SCP) and is bled down to prevent it from exceeding its MAWOP, except during initial startup operations described in § 250.521;
(e) Any hybrid well with casing or riser pressure exceeding 100 psig; or
(f) Any subsea well with a casing pressure 100 psig greater than the external hydrostatic pressure at the subsea wellhead.
Within 14 days after you perform a casing diagnostic test requiring action under § 250.524:
The following information must be included in the notification of corrective
(a) Lessee or Operator name;
(b) Area name and OCS block number;
(c) Well name and API number; and
(d) Casing diagnostic test data.
The following information must be included in the casing pressure request:
(a) API number;
(b) Lease number;
(c) Area name and OCS block number;
(d) Well number;
(e) Company name and mailing address;
(f) All casing, riser, and tubing sizes, weights, grades, and MIYP;
(g) All casing/riser calculated MAWOPs;
(h) All casing/riser pre-bleed down pressures;
(i) Shut-in tubing pressure;
(j) Flowing tubing pressure;
(k) Date and the calculated daily production rate during last well test (oil, gas, basic sediment, and water);
(l) Well status (shut-in, temporarily abandoned, producing, injecting, or gas lift);
(m) Well type (dry tree, hybrid, or subsea);
(n) Date of diagnostic test;
(o) Well schematic;
(p) Water depth;
(q) Volumes and types of fluid bled from each casing or riser evaluated;
(r) Type of diagnostic test performed:
(1) Bleed down/buildup test;
(2) Shut-in the well and monitor the pressure drop test;
(3) Constant production rate and decrease the annular pressure test;
(4) Constant production rate and increase the annular pressure test;
(5) Change the production rate and monitor the casing pressure test; and
(6) Casing pressure and tubing pressure history plot;
(s) The casing diagnostic test data for all casing exceeding 100 psig;
(t) Associated shoe strengths for casing shoes exposed to annular fluids;
(u) Concentration of any H2S that may be present;
(v) Whether the structure on which the well is located is manned or unmanned;
(w) Additional comments; and
(x) Request date.
Casing pressure requests are approved by the Regional Supervisor, Field Operations, for a term to be determined by the Regional Supervisor on a case-by-case basis. The Regional Supervisor may impose additional restrictions or requirements to allow continued operation of the well.
(a) If your casing pressure request is denied, then the operating company must submit plans for corrective action to the respective District Manager within 30 days of receiving the denial. The District Manager will establish a specific time period in which this corrective action will be taken. You must notify the respective District Manager within 30 days after completion of your corrected action.
(b) You must submit the casing diagnostic test data to the appropriate Regional Supervisor, Field Operations, within 14 days of completion of the diagnostic test required under § 250.522(e).
A casing pressure request becomes invalid when:
(a) The casing or riser pressure increases by 200 psig over the approved casing pressure request pressure;
(b) The approved term ends;
(c) The well is worked-over, side-tracked, redrilled, recompleted, or acid stimulated;
(d) A different casing or riser on the same well requires a casing pressure request; or
(e) A well has more than one casing operating under a casing pressure request and one of the casing pressure requests become invalid, then all casing pressure requests for that well become invalid.
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
(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 Manager. 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 Manager 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
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 Manager to determine specific operating requirements, field well-workover rules may be established on the District Manager'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-workover rules may be amended or canceled for cause at any time upon the initiative of the District Manager or upon the request of a lessee.
(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 Manager. Approval for these operations must be requested on Form MMS-124, Application for Permit to Modify.
(b) You must submit the following 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;
(3) Where the well-workover is in a zone known to contain H
(4) Payment of the service fee listed in § 250.125.
(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, Application for Permit to Modify, shall be submitted to the District Manager, 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, End of Operations Report, shall be submitted to the District Manager 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 must meet the appropriate standards from the following table:
(c) The BOP systems for well-workover operations with the tree removed must 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. Accumulator regulators supplied by rig air and without a secondary source of pneumatic supply, must 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 with the tree in place and performed through the wellhead inside of conventional tubing using small-diameter jointed pipe (usually
(1) Two sets of pipe rams, and
(2) One set of blind rams.
(e) The subsea BOP system for well-workover operations must meet the requirements in § 250.442 of this part.
(f) For coiled tubing operations with the production tree in place, you must meet the following minimum requirements for the BOP system:
(1) BOP system components must be in the following order from the top down:
(2) You may use a set of hydraulically-operated combination rams for the blind rams and shear rams.
(3) You may use a set of hydraulically-operated combination rams for the hydraulic two-way slip rams and the hydraulically-operated pipe rams.
(4) You must attach a dual check valve assembly to the coiled tubing connector at the downhole end of the coiled tubing string for all coiled tubing well-workover operations. If you plan to conduct operations without downhole check valves, you must describe alternate procedures and equipment in Form MMS-124, Application for Permit to Modify and have it approved by the District Manager.
(5) You must have a kill line and a separate choke line. You must equip each line with two full-opening valves and at least one of the valves must be remotely controlled. You may use a manual valve instead of the remotely controlled valve on the kill line if you install a check valve between the two full-opening manual valves and the pump or manifold. The valves must have a working pressure rating equal to or greater than the working pressure rating of the connection to which they are attached, and you must install them between the well control stack and the choke or kill line. For operations with expected surface pressures greater than 3,500 psi, the kill line must be connected to a pump or manifold. You must not use the kill line inlet on the BOP stack for taking fluid returns from the wellbore.
(6) You must have a hydraulic-actuating system that provides sufficient accumulator capacity to close-open-close each component in the BOP stack. This cycle must be completed with at least 200 psi above the pre-charge pressure, without assistance from a charging system.
(7) All connections used in the surface BOP system from the tree to the uppermost required ram must be flanged, including the connections between the well control stack and the first full-opening valve on the choke line and the kill line.
(g) 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,
(1) One set of pipe rams hydraulically operated, and
(2) Two sets of stripper-type pipe rams hydraulically operated with spacer spool.
(h) 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)
(1)
(2)
(3)
(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) You may conduct a stump test for the BOP system on location. A plan describing the stump test procedures must be included in your Form MMS-124, Application for Permit to Modify, and must be approved by the District Manager.
(e) You must test the coiled tubing connector to a low pressure of 200 to 300 psi, followed by a high pressure test to the rated working pressure of the connector or the expected surface pressure, whichever is less. You must successfully pressure test the dual check valves to the rated working pressure of the connector, the rated working pressure of the dual check valve, expected surface pressure, or the collapse pressure of the coiled tubing, whichever is less.
(f) You must record test pressures during BOP and coiled tubing tests on a pressure chart, or with a digital recorder, unless otherwise approved by the District Manager. The test interval for each BOP system component must be 5 minutes, except for coiled tubing operations, which must include a 10 minute high-pressure test for the coiled tubing string. Your representative at the facility must certify that the charts are correct.
(g) 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 activity, all such records shall be retained for a period of 2 years
(h) Stump test a subsea BOP system before installation. You must:
(1) Test all ROV intervention functions on your subsea BOP stack during the stump test. You must also test at least one set of rams during the initial test on the seafloor. You must submit test procedures with your APM for District Manager approval. You must:
(i) Ensure that the ROV hot stabs are function tested and are capable of actuating, at a minimum, one set of pipe rams and one set of blind-shear rams and unlatching the LMRP;
(ii) Document all your test results and make them available to BOEMRE upon request; and
(2) Function test autoshear and deadman systems on your subsea BOP stack during the stump test. You must also test the deadman system during the initial test on the seafloor. You must:
(i) Submit test procedures with your APM for District Manager approval.
(ii) Document the results of each test and make them available to BOEMRE upon request.
(3) 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.
(a)
(2) You must visually inspect your BOP system and marine riser at least once each day if weather and sea conditions permit. You may use television cameras to inspect this equipment. The District Manager may approve alternate methods and frequencies to inspect a marine riser.
(b)
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 Manager.
(c) When reinstalling the tree, you must:
(1) Equip wells to monitor for casing pressure according to the following chart:
(2) Follow the casing pressure management requirements in subpart E of this part.
(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) 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 other extreme environmental conditions that may occur in the area. Production shall not commence until the production safety system has been approved and a preproduction inspection has been requested by the lessee.
(b) For all new floating production systems (FPSs) (e.g., column-stabilized-units (CSUs); floating production, storage and offloading facilities (FPSOs); tension-leg platforms (TLPs); spars, etc.), you must do all of the following:
(1) Comply with API RP 14J (incorporated by reference as specified in 30 CFR 250.198);
(2) Meet the drilling and production riser standards of API RP 2RD (incorporated by reference as specified in 30 CFR 250.198);
(3) Design all stationkeeping systems for floating facilities to meet the standards of API RP 2SK (incorporated by reference as specified in 30 CFR
(4) Design stationkeeping systems for floating facilities to meet structural requirements in subpart I, §§ 250.900 through 250.921 of this part.
(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 Manager.
(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 must be inspected, installed, maintained, and tested in accordance with American Petroleum Institute Recommended Practice 14B, Recommended Practice for Design, Installation, Repair, and Operation of Subsurface Safety Valve Systems (incorporated by reference as specified in § 250.198).
(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 Manager.
(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 piping flow diagram (API RP 14C, Figure E, incorporated by reference as specified in § 250.198) and the related Safety analysis Function Evaluation chart (API RP 14C, subsection 4.3c, incorporated by reference as specified in § 250.198).
(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 (incorporated by reference as specified in § 250.198).
(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 (incorporated by reference as specified in § 250.198), 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 Manager 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.
(7) The service fee listed in § 250.125. The fee you must pay will be determined by the number of components
(a) For all production platforms, you must comply with the following production safety system requirements, in addition to the requirements of § 250.802 of this subpart and the requirements of API RP 14C (incorporated by reference as specified in 30 CFR 250.198).
(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 Manager. 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 Manager 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 Manager. 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 the valve(s) to close before exceeding the maximum allowable working pressure.
(iii) If you are installing flowlines constructed of unbonded flexible pipe on a floating platform, you must:
(A) Review the manufacturer's Design Methodology Verification Report and the independent verification agent's (IVA's) certificate for the design methodology contained in that report to ensure that the manufacturer has complied with the requirements of API Spec 17J (incorporated by reference as specified in 30 CFR 250.198);
(B) Determine that the unbonded flexible pipe is suitable for its intended purpose on the lease or pipeline right-of-way;
(C) Submit to the MMS District Manager the manufacturer's design specifications for the unbonded flexible pipe; and
(D) Submit to the MMS District Manager a statement certifying that the pipe is suitable for its intended use and that the manufacturer has complied with the IVA requirements of API Spec 17J (incorporated by reference as specified in 30 CFR 250.198).
(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 Manager.
(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 Manager.
(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 designated 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 Manager, 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 fixed firewater monitors shall be installed. The firewater system shall be installed to provide needed protection in all areas where production-handling equipment is located. A fixed waterspray system shall be installed in enclosed well-bay areas where hydrocarbon vapors may accumulate.
(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 Manager.
(iii) A firefighting system using chemicals may be used in lieu of a water system if the District Manager 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 Manager 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 Manager may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(v) Fire- and gas-detection systems must be an approved type, designed and installed according to API RP 14C, API RP 14G, and either API RP 14F or API RP 14FZ (the preceding four documents incorporated by reference as specified in § 250.198).
(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, you are not required to comply with the provisions of API RP 14C (incorporated by reference as specified in § 250.198) 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)
For
(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 (excluding electronic pressure transmitters and level sensors) must be tested at least once each calendar month, but at no time will 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) The following electronic pressure transmitters and level sensors must be tested at least once every 3 months, but at no time may more than 120 days elapse between tests:
(i) All PSH and PSL, and
(ii) All LSH and LSL controls.
(5) 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 SSV's and USV's must be tested in accordance with the test procedures specified in API RP 14H (incorporated by reference as specified in § 250.198). If the SSV or USV does not operate properly or if any fluid flow is observed during the leakage test, the valve shall be repaired or replaced.
(6) 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 must be tested for leakage in accordance with the test procedures specified in API RP 14C, Appendix D, section D4, table D2, subsection D (incorporated by reference as specified in § 250.198). 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.
(7) 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.
(8) All pumps for firewater systems shall be inspected and operated weekly.
(9) 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.
(10) All TSH devices shall be tested at least once every 12 months, excluding those addressed in paragraph (a)(7) 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.
(11) 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.
(12) Prior to the commencement of production, the lessee shall notify the District Manager when the lessee is ready to conduct a preproduction test and inspection of the integrated safety system. The lessee shall also notify the District Manager 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-1-1994 and SPPE-1d-1996 Addenda, 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 for the Petroleum, Petrochemical and Natural Gas Industry (incorporated by reference as specified in § 250.198).
(3) All SSV's and USV's must meet the technical specifications of API Spec 6A and 6AV1. All SSSVs must meet the technical specifications of API Specification 14A (incorporated by reference as specified in § 250.198). However, SSSVs and related equipment planned to be used in high pressure high temperature environments must meet the additional requirements set forth in § 250.807.
(4) For information on all standards mentioned in this section, see § 250.198.
(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
(c)
(a) If you plan to install SSSVs and related equipment in an HPHT environment, you must submit detailed information with your Application for Permit to Drill (APD), Application for Permit to Modify (APM), or Deepwater Operations Plan (DWOP) that demonstrates the SSSVs and related equipment are capable of performing in the applicable HPHT environment. Your detailed information must include the following:
(1) A discussion of the SSSVs' and related equipment's design verification analysis;
(2) A discussion of the SSSVs' and related equipment's design validation and functional testing process and procedures used; and
(3) An explanation of why the analysis, process, and procedures ensure that the SSSVs and related equipment are fit-for-service in the applicable HPHT environment.
(b) For this section, HPHT environment means when one or more of the following well conditions exist:
(1) The completion of the well requires completion equipment or well control equipment assigned a pressure rating greater than 15,000 psig or a temperature rating greater than 350 degrees Fahrenheit;
(2) The maximum anticipated surface pressure or shut-in tubing pressure is greater than 15,000 psig on the seafloor for a well with a subsea wellhead or at the surface for a well with a surface wellhead; or
(3) The flowing temperature is equal to or greater than 350 degrees Fahrenheit on the seafloor for a well with a subsea wellhead or at the surface for a well with a surface wellhead.
(c) For this section, related equipment includes wellheads, tubing heads, tubulars, packers, threaded connections, seals, seal assemblies, production trees, chokes, well control equipment, and any other equipment that will be exposed to the HPHT environment.
Production operations in zones known to contain hydrogen sulfide (H
(a) You must design, fabricate, install, use, maintain, inspect, and assess all platforms and related structures on the Outer Continental Shelf (OCS) so as to ensure their structural integrity for the safe conduct of drilling, workover, and production operations. In doing this, you must consider the specific environmental conditions at the platform location.
(b) You must also submit an application under § 250.905 of this subpart and
(c) Under emergency conditions, you may make repairs to primary structural elements to restore an existing permitted condition without submitting an application or receiving prior MMS approval for up to 120-calendar days following an event. You must notify the Regional Supervisor of the damage that occurred within 24 hours of its discovery, and you must provide a written completion report to the Regional Supervisor of the repairs that were made within 1 week after completing the repairs. If you make emergency repairs on a floating platform, you must also notify the USCG.
(d) You must determine if your new platform or major modification to an existing platform is subject to the Platform Verification Program (PVP). Section 250.910 of this subpart fully describes the facilities that are subject to the PVP. If you determine that your platform is subject to the PVP, you must follow the requirements of §§ 250.909-250.918 of this subpart.
(e) You must submit notification of the platform installation date and the final as-built location data to the Regional Supervisor within 45-calendar days of completion of platform installation.
(1) For platforms not subject to the Platform Verification Program (PVP), MMS will cancel the approved platform application 1 year after the approval has been granted if the platform has not been installed. If MMS cancels the approval, you must resubmit your platform application and receive MMS approval if you still plan to install the platform.
(2) For platforms subject to the PVP, cancellation of an approval will be on an individual platform basis. For these platforms, MMS will identify the date when the installation approval will be cancelled (if installation has not occurred) during the application and approval process. If MMS cancels your installation approval, you must resubmit your platform application and receive
(a) In addition to the other requirements of this subpart, your plans for platform design, analysis, fabrication, installation, use, maintenance, inspection and assessment must, as appropriate, conform to:
(1) ACI Standard 318-95, Building Code Requirements for Reinforced Concrete (ACI 318-95) and Commentary (ACI 318R-95) (incorporated by reference at § 250.198);
(2) ACI 357R-84, Guide for the Design and Construction of Fixed Offshore Concrete Structures, 1984; reapproved 1997 (incorporated by reference at § 250.198);
(3) ANSI/AISC 360-05, Specification for Structural Steel Buildings, (incorporated by reference as specified in § 250.198);
(4) American Petroleum Institute (API) Bulletin 2INT-DG, Interim Guidance for Design of Offshore Structures for Hurricane Conditions, (incorporated by reference as specified in § 250.198);
(5) API Bulletin 2INT-EX, Interim Guidance for Assessment of Existing Offshore Structures for Hurricane Conditions, (incorporated by reference as specified in § 250.198);
(6) API Bulletin 2INT-MET, Interim Guidance on Hurricane Conditions in the Gulf of Mexico, (incorporated by reference as specified in § 250.198);
(7) API Recommend Practice (RP) 2A-WSD, RP for Planning, Designing, and Constructing Fixed Offshore Platforms—Working Stress Design (incorporated by reference as specified in § 250.198);
(8) API RP 2FPS, Recommended Practice for Planning, Designing, and Constructing Floating Production Systems, (incorporated by reference as specified in § 250.198);
(9) API RP 2I, In-Service Inspection of Mooring Hardware for Floating Drilling Units (incorporated by reference as specified in § 250.198);
(10) API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLPs), (incorporated by reference as specified in § 250.198);
(11) API RP 2SK, Recommended Practice for Design and Analysis of Station Keeping Systems for Floating Structures, (incorporated by reference as specified in § 250.198);
(12) API RP 2SM, Recommended Practice for Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, (incorporated by reference as specified in § 250.198);
(13) API RP 2T, Recommended Practice for Planning, Designing and Constructing Tension Leg Platforms, (incorporated by reference as specified in § 250.198);
(14) API RP 14J, Recommended Practice for Design and Hazards Analysis for Offshore Production Facilities, (incorporated by reference as specified in § 250.198);
(15) American Society for Testing and Materials (ASTM) Standard C 33-07, approved December 15, 2007, Standard Specification for Concrete Aggregates (incorporated by reference as specified in § 250.198);
(16) ASTM Standard C 94/C 94M-07, approved January 1, 2007, Standard Specification for Ready-Mixed Concrete (incorporated by reference as specified in § 250.198);
(17) ASTM Standard C 150-07, approved May 1, 2007, Standard Specification for Portland Cement (incorporated by reference as specified in § 250.198);
(18) ASTM Standard C 330-05, approved December 15, 2005, Standard Specification for Lightweight Aggregates for Structural Concrete (incorporated by reference as specified in § 250.198);
(19) ASTM Standard C 595-08, approved January 1, 2008, Standard Specification for Blended Hydraulic Cements (incorporated by reference as specified in § 250.198);
(20) AWS D1.1, Structural Welding Code—Steel, including Commentary, (incorporated by reference as specified in § 250.198);
(21) AWS D1.4, Structural Welding Code—Reinforcing Steel, (incorporated by reference as specified in § 250.198);
(22) AWS D3.6M, Specification for Underwater Welding, (incorporated by reference as specified in § 250.198);
(23) NACE Standard MR0175, Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment, (incorporated by reference as specified in § 250.198);
(24) NACE Standard RP0176-2003, Item No. 21018, Standard Recommended Practice, Corrosion Control of Steel Fixed Offshore Structures Associated with Petroleum Production.
(b) You must follow the requirements contained in the documents listed under paragraph (a) of this section insofar as they do not conflict with other provisions of 30 CFR part 250. You may use applicable provisions of these documents, as approved by the Regional Supervisor, for the design, fabrication, and installation of platforms such as spars, since standards specifically written for such structures do not exist. You may also use alternative codes, rules, or standards, as approved by the Regional Supervisor, under the conditions enumerated in § 250.141.
(c) For information on the standards mentioned in this section, and where they may be obtained, see § 250.198 of this part.
(d) The following chart summarizes the applicability of the industry standards listed in this section for fixed and floating platforms:
You must remove all structures according to §§ 250.1725 through 250.1730 of Subpart Q—Decommissioning Activities of this part.
(a) You must compile, retain, and make available to MMS representatives for the functional life of all platforms:
(1) The as-built drawings;
(2) The design assumptions and analyses;
(3) A summary of the fabrication and installation nondestructive examination records;
(4) The inspection results from the inspections required by § 250.919 of this subpart; and
(5) Records of repairs not covered in the inspection report submitted under § 250.919(b).
(b) You must record and retain the original material test results of all primary structural materials during all stages of construction. Primary material is material that, should it fail, would lead to a significant reduction in platform safety, structural reliability, or operating capabilities. Items such as steel brackets, deck stiffeners and secondary braces or beams would not generally be considered primary structural members (or materials).
(c) You must provide MMS with the location of these records in the certification statement of your application for platform approval as required in § 250.905(j).
(a) The Platform Approval Program is the MMS basic approval process for platforms on the OCS. The requirements of the Platform Approval Program are described in §§ 250.904 through 250.908 of this subpart. Completing these requirements will satisfy MMS criteria for approval of fixed platforms of a proven design that will be placed in the shallow water areas (≤ 400 ft.) of the Gulf of Mexico OCS.
(b) The requirements of the Platform Approval Program must be met by all platforms on the OCS. Additionally, if you want approval for a floating platform; a platform of unique design; or a platform being installed in deepwater (> 400 ft.) or a frontier area, you must also meet the requirements of the Platform Verification Program. The requirements of the Platform Verification Program are described in §§ 250.909 through 250.918 of this subpart.
The Platform Approval Program requires that you submit the information, documents, and fee listed in the following table for your proposed project. In lieu of submitting the paper copies specified in the table, you may submit your application electronically in accordance with 30 CFR 250.186(a)(3).
(a)
(1) Shallow faults;
(2) Gas seeps or shallow gas;
(3) Slump blocks or slump sediments;
(4) Shallow water flows;
(5) Hydrates; or
(6) Ice scour of seafloor sediments.
(b)
(1) Seismic activity at your proposed site;
(2) Fault zones, the extent and geometry of faulting, and attenuation effects of geologic conditions near your site; and
(3) For platforms located in producing areas, the possibility and effects of seafloor subsidence.
(c)
(d)
(1) Scouring of the seafloor;
(2) Hydraulic instability;
(3) The occurrence of sand waves;
(4) Instability of slopes at the platform location;
(5) Liquifaction, or possible reduction of soil strength due to increased pore pressures;
(6) Degradation of subsea permafrost layers;
(7) Cyclic loading;
(8) Lateral loading;
(9) Dynamic loading;
(10) Settlements and displacements;
(11) Plastic deformation and formation collapse mechanisms; and
(12) Soil reactions on the platform foundations or anchoring systems.
(a) For fixed or bottom-founded platforms and tension leg platforms, your maximum distance from any foundation pile to a soil boring must not exceed 500 feet.
(b) For deepwater floating platforms which utilize catenary or taut-leg moorings, you must take borings at the most heavily loaded anchor location, at the anchor points approximately 120 and 240 degrees around the anchor pattern from that boring, and, as necessary, other points throughout the anchor pattern to establish the soil profile suitable for foundation design purposes.
(a) API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms (incorporated by reference as specified in 30 CFR 250.198), requires that the design fatigue life of each joint and member be twice the intended service life of the structure. When designing your platform, the following table provides minimum fatigue life safety factors for critical structural members and joints.
(b) The documents incorporated by reference in § 250.901 may require larger safety factors than indicated in paragraph (a) of this section for some key components. When the documents incorporated by reference require a larger safety factor than the chart in paragraph (a) of this section, the requirements of the incorporated document will prevail.
The Platform Verification Program is the MMS approval process for ensuring that floating platforms; platforms of a new or unique design; platforms in seismic areas; or platforms located in deepwater or frontier areas meet stringent requirements for design and construction. The program is applied during construction of new platforms and major modifications of, or repairs to, existing platforms. These requirements are in addition to the requirements of the Platform Approval Program described in §§ 250.904 through 250.908 of this subpart.
(a) All new fixed or bottom-founded platforms that meet any of the following five conditions are subject to the Platform Verification Program:
(1) Platforms installed in water depths exceeding 400 feet (122 meters);
(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.
(b) All new floating platforms are subject to the Platform Verification Program to the extent indicated in the following table:
(c) If a platform is originally subject to the Platform Verification Program, then the conversion of that platform at that same site for a new purpose, or making a major modification of, or major repair to, that platform, is also
(d) The applicability of Platform Verification Program requirements to other types of facilities will be determined by MMS on a case-by-case basis.
If your platform, conversion, or major modification or repair meets the criteria in § 250.910, you must:
(a) Design, fabricate, install, use, maintain and inspect your platform, conversion, or major modification or repair to your platform according to the requirements of this subpart, and the applicable documents listed in § 250.901(a) of this subpart;
(b) Comply with all the requirements of the Platform Approval Program found in §§ 250.904 through 250.908 of this subpart.
(c) Submit for the Regional Supervisor's approval three copies each of the design verification, fabrication verification, and installation verification plans required by § 250.912;
(d) Submit a complete schedule of all phases of design, fabrication, and installation for the Regional Supervisor's approval. You must include a project management timeline, Gantt Chart, that depicts when interim and final reports required by §§ 250.916, 250.917, and 250.918 will be submitted to the Regional Supervisor for each phase. On the timeline, you must break-out the specific scopes of work that inherently stand alone (e.g., deck, mooring systems, tendon systems, riser systems, turret systems).
(e) Include your nomination of a Certified Verification Agent (CVA) as a part of each verification plan required by § 250.912;
(f) Follow the additional requirements in §§ 250.913 through 250.918;
(g) Obtain approval for modifications to approved plans and for major deviations from approved installation procedures from the Regional Supervisor; and
(h) Comply with applicable USCG regulations for floating OCS facilities.
If your platform, associated structure, or major modification meets the criteria in § 250.910, you must submit the following plans to the Regional Supervisor for approval:
(a)
(1) All design documentation specified in § 250.905 of this subpart;
(2) Abstracts of the computer programs used in the design process; and
(3) A summary of the major design considerations and the approach to be used to verify the validity of these design considerations.
(b)
(1) Fabrication drawings and material specifications for artificial island
(2) For jacket and floating structures, all the primary load-bearing members included in the space-frame analysis; and
(3) A summary description of the following:
(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 for welds and materials; and
(vii) Quality assurance procedures.
(c)
(1) A summary description of the planned marine operations;
(2) Contingencies considered;
(3) Alternative courses of action; and
(4) An identification of the areas to be inspected. You must specify the acceptance and rejection criteria to be used for any inspections conducted during installation, and for the post-installation verification inspection.
(d) You must combine fabrication verification and installation verification plans for manmade islands or platforms fabricated and installed in place.
(a) You must resubmit any design verification, fabrication verification, or installation verification plan to the Regional Supervisor for approval if:
(1) The CVA changes;
(2) The CVA's or assigned personnel's qualifications change; or
(3) The level of work to be performed changes.
(b) If only part of a verification plan is affected by one of the changes described in paragraph (a) of this section, you can resubmit only the affected part. You do not have to resubmit the summary of technical details unless you make changes in the technical details.
(a) As part of your design verification, fabrication verification, or installation verification plan, you must nominate a CVA for the Regional Supervisor's approval. You must specify whether the nomination is for the design, fabrication, or installation phase of verification, or for any combination of these phases.
(b) For each CVA, you must submit a list of documents to be forwarded to the CVA, and a qualification statement that includes the following:
(1) Previous experience in third-party verification or experience in the design, fabrication, installation, or major modification of offshore oil and gas platforms. This should include fixed platforms, floating platforms, manmade islands, other similar marine structures, and related systems and equipment;
(2) Technical capabilities of the individual or the primary staff for the specific project;
(3) Size and type of organization or corporation;
(4) In-house availability of, or access to, appropriate technology. This should include computer programs, hardware, and testing materials and equipment;
(5) Ability to perform the CVA functions for the specific project considering current commitments;
(6) Previous experience with MMS requirements and procedures;
(7) The level of work to be performed by the CVA.
(a) The CVA must conduct specified reviews according to §§ 250.916, 250.917, and 250.918 of this subpart.
(b) Individuals or organizations acting as CVAs must not function in any capacity that would create a conflict of interest, or the appearance of a conflict of interest.
(c) The CVA must consider the applicable provisions of the documents listed in § 250.901(a); the alternative codes, rules, and standards approved under 250.901(b); and the requirements of this subpart.
(d) The CVA is the primary contact with the Regional Supervisor and is directly responsible for providing immediate reports of all incidents that affect the design, fabrication and installation of the platform.
(a) The CVA must use good engineering judgement and practices in conducting an independent assessment of the design of the platform, major modification, or repair. The CVA must ensure that the platform, major modification, or repair is designed to withstand the environmental and functional load conditions appropriate for the intended service life at the proposed location.
(b) Primary duties of the CVA during the design phase include the following:
(c) The CVA must submit interim reports and a final report to the Regional Supervisor, and to you, during the design phase in accordance with the approved schedule required by § 250.911(d). In each interim and final report the CVA must:
(1) Provide a summary of the material reviewed and the CVA's findings;
(2) In the final CVA report, make a recommendation that the Regional Supervisor either accept, request modifications, or reject the proposed design unless such a recommendation has been previously made in an interim report;
(3) Describe the particulars of how, by whom, and when the independent review was conducted; and
(4) Provide any additional comments the CVA deems necessary.
(a) The CVA must use good engineering judgement and practices in conducting an independent assessment of the fabrication activities. The CVA must monitor the fabrication of the platform or major modification to ensure that it has been built according to the approved design and the fabrication plan. If the CVA finds that fabrication procedures are changed or design specifications are modified, the CVA must inform you. If you accept the modifications, then the CVA must so inform the Regional Supervisor.
(b) Primary duties of the CVA during the fabrication phase include the following:
(c) The CVA must submit interim reports and a final report to the Regional Supervisor, and to you, during the fabrication phase in accordance with the approved schedule required by § 250.911(d). In each interim and final report the CVA must:
(1) Give details of how, by whom, and when the independent monitoring activities were conducted;
(2) Describe the CVA's activities during the verification process;
(3) Summarize the CVA's findings;
(4) Confirm or deny compliance with the design specifications and the approved fabrication plan;
(5) In the final CVA report, make a recommendation to accept or reject the fabrication unless such a recommendation has been previously made in an interim report; and
(6) Provide any additional comments that the CVA deems necessary.
(a) The CVA must use good engineering judgment and practice in conducting an independent assessment of the installation activities.
(b) Primary duties of the CVA during the installation phase include the following:
(c) The CVA must submit interim reports and a final report to the Regional Supervisor, and to you, during the installation phase in accordance with the approved schedule required by § 250.911(d). In each interim and final report the CVA must:
(1) Give details of how, by whom, and when the independent monitoring activities were conducted;
(2) Describe the CVA's activities during the verification process;
(3) Summarize the CVA's findings;
(4) Confirm or deny compliance with the approved installation plan;
(5) In the final report, make a recommendation to accept or reject the installation unless such a recommendation has been previously made in an interim report; and
(6) Provide any additional comments that the CVA deems necessary.
(a) You must submit a comprehensive in-service inspection report annually by November 1 to the Regional Supervisor that must include:
(1) A list of fixed and floating platforms you inspected in the preceding 12 months;
(2) The extent and area of inspection for both the above-water and underwater portions of the platform and the pertinent components of the mooring system for floating platforms;
(3) The type of inspection employed (e.g., visual, magnetic particle, ultrasonic testing);
(4) The overall structural condition of each platform, including a corrosion protection evaluation; and
(5) A summary of the inspection results indicating what repairs, if any, were needed.
(b) If any of your structures have been exposed to a natural occurrence (e.g., hurricane, earthquake, or tropical storm), the Regional Supervisor may require you to submit an initial report of all structural damage, followed by subsequent updates, which include the following:
(1) A list of affected structures;
(2) A timetable for conducting the inspections described in section 14.4.3 of API RP 2A-WSD (incorporated by reference as specified in § 250.198); and
(3) An inspection plan for each structure that describes the work you will perform to determine the condition of the structure.
(c) The Regional Supervisor may also require you to submit the results of the inspections referred to in paragraph (b)(2) of this section, including a description of any detected damage that may adversely affect structural integrity, an assessment of the structure's
(a) You must document all wells, equipment, and pipelines supported by the platform if you intend to use either the A-2 or A-3 assessment category. Assessment categories are defined in API RP 2A-WSD, Section 17.3. If MMS objects to the assessment category you used for your assessment, you may need to redesign and/or modify the platform to adequately demonstrate that the platform is able to withstand the environmental loadings for the appropriate assessment category.
(b) You must perform an analysis check when your platform will have additional personnel, additional topside facilities, increased environmental or operational loading, or inadequate deck height your platform suffered significant damage (e.g., experienced damage to primary structural members or conductor guide trays or global structural integrity is adversely affected); or the exposure category changes to a more restrictive level (see Sections 17.2.1 through 17.2.5 of API RP 2A-WSD for a description of assessment initiators).
(c) You must initiate mitigation actions for platforms that do not pass the assessment process of API RP 2A-WSD. You must submit applications for your mitigation actions (e.g., repair, modification, decommissioning) to the Regional Supervisor for approval before you conduct the work.
(d) The MMS may require you to conduct a platform design basis check when the reduced environmental loading criteria contained in API RP 2A-WSD Section 17.6 are not applicable.
(e) By November 1, 2009, you must submit a complete list of all the platforms you operate, together with all the appropriate data to support the assessment category you assign to each platform and the platform assessment initiators (as defined in API RP 2A-WSD) to the Regional Supervisor. You must submit subsequent complete lists and the appropriate data to support the consequence-of-failure category every 5 years thereafter, or as directed by the Regional Supervisor.
(f) The use of Section 17, Assessment of Existing Platforms, of API RP 2A-WSD is limited to existing fixed structures that are serving their original approved purpose. You must obtain approval from the Regional Supervisor for any change in purpose of the platform, following the provisions of API RP 2A-WSD, Section 15, Re-use.
(a) If you are required to analyze cumulative fatigue on your platform because of the results of an inspection or platform assessment, you must ensure that the safety factors for critical elements listed in § 250.908 are met or exceeded.
(b) If the calculated life of a joint or member does not meet the criteria of § 250.908, you must either mitigate the load, strengthen the joint or member, or develop an increased inspection process.
(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 must be accompanied by payment of the service fee listed in § 250.125 and submitted to the Regional Supervisor and approval obtained before:
(1) Installation, modification, or abandonment of a lease term pipeline;
(2) Installation or modification of a right-of-way (other than lease term) pipeline; or
(3) 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.
(6) Any producer operating a pipeline that crosses into State waters without first connecting to a transporting operator's facility on the OCS must comply with this subpart. Compliance must extend from the point where hydrocarbons are first produced, through and including the last valve and associated safety equipment (e.g., pressure safety sensors) on the last production facility on the OCS.
(7) Any producer operating a pipeline that connects facilities on the OCS must comply with this subpart.
(8) Any operator of a pipeline that has a valve on the OCS downstream (landward) of the last production facility may ask in writing that the MMS Regional Supervisor recognize that valve as the last point MMS will exercise its regulatory authority.
(9) A pipeline segment is not subject to MMS regulations for design, construction, operation, and maintenance if:
(i) It is downstream (generally shoreward) of the last valve and associated safety equipment on the last production facility on the OCS; and
(ii) It is subject to regulation under 49 CFR parts 192 and 195.
(10) DOT may inspect all upstream safety equipment (including valves, over-pressure protection devices, cathodic protection equipment, and pigging devices, etc.) that serve to protect the integrity of DOT-regulated pipeline segments.
(11) OCS pipeline segments not subject to DOT regulation under 49 CFR parts 192 and 195 are subject to all MMS regulations.
(12) A producer may request that its pipeline operate under DOT regulations governing pipeline design, construction, operation, and maintenance.
(i) The operator's request must be in the form of a written petition to the MMS Regional Supervisor that states the justification for the pipeline to operate under DOT regulation.
(ii) The Regional Supervisor will decide, on a case-by-case basis, whether to grant the operator's request. In considering each petition, the Regional Supervisor will consult with the Office
(13) A transporter who operates a pipeline regulated by DOT may request to operate under MMS regulations governing pipeline operation and maintenance. Any subsequent repairs or modifications will also be subject to MMS regulations governing design and construction.
(i) The operator's request must be in the form of a written petition to the OPS Regional Director and the MMS Regional Supervisor.
(ii) The MMS Regional Supervisor and the OPS Regional Director will decide how to act on this petition.
(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-way holder has failed to comply with a provision of the Act or any other applicable law, a provision of these or other applicable regulations, or a condition of a permit or right-of-way grant.
(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:
(1) Producer-operated pipelines extending upstream (generally seaward) from each point on the OCS at which operating responsibility transfers from a producing operator to a transporting operator;
(2) Producer-operated pipelines extending upstream (generally seaward) of the last valve (including associated safety equipment) on the last production facility on the OCS that do not connect to a transporter-operated pipeline on the OCS before crossing into State waters;
(3) Producer-operated pipelines connecting production facilities on the OCS;
(4) Transporter-operated pipelines that DOI and DOT have agreed are to be regulated as DOI pipelines; and
(5) All OCS pipelines not subject to regulation under 49 CFR parts 192 and 195.
(1) Transporter-operated pipelines currently operated under DOT requirements governing design, construction, maintenance, and operation;
(2) Producer-operated pipelines that DOI and DOT have agreed are to be regulated under DOT requirements governing design, construction, maintenance, and operation; and
(3) Producer-operated pipelines downstream (generally shoreward) of the last valve (including associated safety equipment) on the last production facility on the OCS that do not connect to a transporter-operated pipeline on the OCS before crossing into State waters and that are regulated under 49 CFR parts 192 and 195.
(1) Are contained within the boundaries of a single lease or group of unitized leases but are not owned and operated by the lessee or operator of that lease or unit,
(2) Are contained within the boundaries of contiguous (not cornering) leases which do not have a common lessee or operator,
(3) 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
(4) 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 (incorporated by reference as specified in 30 CFR 250.198). 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 strength of the fitting shall at least be equal to the computed bursting strength of the pipe.
(4) If you are installing pipelines constructed of unbonded flexible pipe, you must design them according to the standards and procedures of API Spec 17J, incorporated by reference as specified in 30 CFR 250.198.
(5) You must design pipeline risers for tension leg platforms and other floating platforms according to the design standards of API RP 2RD, Design of Risers for Floating Production Systems (FPSs) and Tension Leg Platforms (TLPs), incorporated by reference as specified in 30 CFR 250.198.
(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) pressure of the pipeline; or
(3) If applicable, the MAOP of the receiving pipeline when the proposed
(d) If the maximum source pressure (MSP) exceeds the pipeline's MAOP, you must install and maintain redundant safety devices meeting the requirements of section A9 of API RP 14C (incorporated by reference as specified in § 250.198). 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 pressure 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 that there is a reasonable likelihood that the line has been damaged or weakened by external or internal conditions.
(c) When a pipeline is repaired utilizing a clamp, the clamp shall be a full
(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 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 must comply with section A7 of API RP 14C (incorporated by reference as specified in § 250.198). 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.
(a) The requirements for decommissioning pipelines are listed in § 250.1750 through § 250.1754.
(b) The table in this section lists the requirements if you take a DOI pipeline out of service:
(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) A description of any additional design precautions you took to enable the pipeline to withstand the effects of water currents, storm or ice scouring, soft bottoms, mudslides, earthquakes, permafrost, and other environmental factors.
(i) If you propose to use unbonded flexible pipe, your application must include:
(A) The manufacturer's design specification sheet;
(B) The design pressure (psi);
(C) An identification of the design standards you used; and
(D) A review by a third-party independent verification agent (IVA) according to API Spec 17J (incorporated by reference as specified in § 250.198), if applicable.
(ii) If you propose to use one or more pipeline risers for a tension leg platform or other floating platform, your application must include:
(A) The design fatigue life of the riser, with calculations, and the fatigue point at which you would replace the riser;
(B) The results of your vortex-induced vibration (VIV) analysis;
(C) An identification of the design standards you used; and
(D) A description of any necessary mitigation measures such as the use of helical strakes or anchoring devices.
(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.
(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 must notify the Regional Supervisor before the repair of any pipeline or as soon as practicable. Your notification must be accompanied by payment of the service fee listed in § 250.125. You must submit a detailed report of the repair of a pipeline or pipeline component to the Regional Supervisor within
(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 action shall be submitted to the Regional Supervisor for approval within 30 days of the observation. A report of the remedial action taken shall be submitted to the Regional Supervisor by the lessee or right-of-way holder within 30 days after completion.
(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) 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.
(b) 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.
An applicant, by accepting a right-of-way grant, agrees to comply with the following requirements:
(a) The right-of-way holder shall comply with applicable laws and regulations and the terms of the grant.
(b) 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-way. Moreover, the holder agrees to allow the occupancy and use by the United States, its lessees, or other right-of-way holders, of any part of the right-of-way grant not actually occupied or necessarily incident to its use for any necessary operations involved in the management, administration, or the enjoyment of such other granted rights.
(c) 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
(d) 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.
(e) 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.
(f)(1) 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.
(2) Unless otherwise exempted by FERC pursuant to 43 U.S.C. 1334(f)(2), the holder shall—
(i) Provide open and nondiscriminatory access to a right-of-way pipeline to both owner and nonowner shippers, and
(ii) 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.
(g) 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.
(h) 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 § 250.1019 of this part.
(a) When you apply for, or are the holder of, a right-of-way, you must:
(1) 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
(2) Provide additional security if the Regional Director determines that a bond in excess of $300,000 is needed.
(b) For the purpose of this paragraph, there are three areas:
(1) The Gulf of Mexico and the area offshore the Atlantic Coast;
(2) The areas offshore the Pacific Coast States of California, Oregon, Washington, and Hawaii; and
(3) The area offshore the Coast of Alaska.
(c) 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.
(d) 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.
(a) You must pay MMS an annual rental of $15 for each statute mile, or part of a statute mile, of the OCS that your pipeline right-of-way crosses.
(b) This paragraph applies to you if you obtain a pipeline right-of-way that includes a site for an accessory to the pipeline, including but not limited to a platform. This paragraph also applies if you apply to modify a right-of-way to change the site footprint. In either case, you must pay the amounts shown in the following table.
(c) If you hold a pipeline right-of-way that includes a site for an accessory to your pipeline and you are not covered by paragraph (b) of this section, then you must pay MMS an annual rental of $75 for use of the affected area.
(d) You may make the rental payments required by paragraphs (a), (b)(1), (b)(2), and (c) of this section on an annual basis, for a 5-year period, or for multiples of 5 years. You must make the first payment at the time you submit the pipeline right-of-way application. You must make all subsequent payments before the respective time periods begin.
(e)
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.
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 made, unless otherwise expressly stated in the grant. Temporary cessation or suspension of pipeline operations shall not cause the grant to expire. However, if the purpose of the grant ceases to exist or use of the associated pipeline is permanently discontinued for any reason, the grant shall be deemed to have expired.
(a) You must submit an original and three copies of an application for a new or modified pipeline ROW 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 ROW grant. If the ROW 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 § 250.1012 of this subpart, as well as the service fees listed in § 250.125 of this part for a pipeline ROW grant to install a new pipeline, or to convert an existing lease term pipeline into a ROW pipeline. An application to modify an approved ROW grant must be accompanied by the additional rental required under § 250.1012 if applicable. You must file a separate application for each ROW.
(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.
(e) Notwithstanding the provisions of paragraph (a) of this section, the requirements to pay filing fees under that paragraph are suspended until January 3, 2006.
(a) In considering an application for a right-of-way, the Regional Supervisor shall consider the potential effect of the associated pipeline on the human,
(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 § 250.1015(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
(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 must be accompanied by the same showing of qualifications of the assignees as is required of an applicant for a ROW in § 250.1015 of this subpart and must be supported by a statement that the assignee agrees to comply with and to be bound by the terms and conditions of the ROW grant. The assignee must satisfy the bonding requirements in § 250.1011 of this subpart. No transfer will be recognized unless and until it is first approved, in writing, by the Regional Supervisor. The assignee must pay the service fee listed in § 250.125 of this part for a pipeline ROW assignment request.
(c) Notwithstanding the provisions of paragraph (b) of this section, the requirement to pay a filing fee under that paragraph is suspended until January 3, 2006.
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 must contain those items addressed in §§ 250.1751 and 250.1752 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 § 250.1010(h) of this part.
You must produce wells and reservoirs at rates that provide for economic development while maximizing ultimate recovery and without adversely affecting correlative rights.
(a) You must conduct well production tests as shown in the following table:
(b) You may request an extension from the Regional Supervisor if you cannot submit the results of a semiannual well test within the specified time.
(c) You must submit to the Regional Supervisor an original and two copies of the appropriate form required by paragraph (a) of this section; one of the copies of the form must be a public information copy in accordance with §§ 250.186 and 250.197, and marked “Public Information.” You must submit two copies of the supporting information as listed in the table in § 250.1167 with form MMS-126.
(a) When you conduct well tests you must:
(1) Recover fluid from the well completion equivalent to the amount of fluid introduced into the formation during completion, recompletion, reworking, or treatment operations before you start a well test;
(2) Produce the well completion under stabilized rate conditions for at least 6 consecutive hours before beginning the test period;
(3) Conduct the test for at least 4 consecutive hours;
(4) Adjust measured gas volumes to the standard conditions of 14.73 pounds per square inch absolute (psia) and 60 °F for all tests; and
(5) Use measured specific gravity values to calculate gas volumes.
(b) You may request approval from the Regional Supervisor to conduct a well test using alternative procedures if you can demonstrate test reliability under those procedures.
(c) The Regional Supervisor may also require you to conduct the following tests and complete them within a specified time period:
(1) A retest or a prolonged test of a well completion if it is determined to be necessary for the proper establishment of a Maximum Production Rate (MPR) or a Maximum Efficient Rate (MER); and
(2) A multipoint back-pressure test to determine the theoretical open-flow potential of a gas well.
(d) An MMS representative may witness any well test. Upon request, you must provide advance notice to the Regional Supervisor of the times and dates of well tests.
(a) You must conduct a static bottomhole pressure survey under the following conditions:
(b) Your bottomhole pressure survey must meet the following requirements:
(1) You must shut-in the well for a minimum period of 4 hours to ensure stabilized conditions; and
(2) The bottomhole pressure survey must consist of a pressure measurement at mid-perforation, and pressure measurements and gradient information for at least four gradient stops coming out of the hole.
(c) You must submit to the Regional Supervisor the results of all static bottomhole pressure surveys on Form
(d) The Regional Supervisor may grant a departure from the requirement to run a static bottomhole pressure survey. To request a departure, you must submit a justification, along with Form MMS-140, Bottomhole Pressure Survey Report, showing a calculated bottomhole pressure or any measured data.
(a) You must determine whether each reservoir is sensitive. You must classify the reservoir as sensitive if:
(1) Under initial conditions it is an oil reservoir with an associated gas cap;
(2) At any time there are near-critical fluids; or
(3) The reservoir is undergoing enhanced recovery.
(b) For the purposes of this subpart, near-critical fluids are:
(1) Those fluids that occur in high temperature, high-pressure reservoirs where it is not possible to define the liquid-gas contact; or
(2) Fluids in reservoirs that are near bubble point or dew point conditions.
(c) The Regional Supervisor may reclassify a reservoir when available information warrants reclassification.
(d) If available information indicates that a reservoir previously classified as non-sensitive is now sensitive, you must submit a request to the Regional Supervisor to reclassify the reservoir. You must include supporting information, as listed in the table in § 250.1167, with your request.
(e) If information indicates that a reservoir previously classified as sensitive is now non-sensitive, you may submit a request to the Regional Supervisor to reclassify the reservoir. You must include supporting information, as listed in the table in § 250.1167, with your request.
You must submit to the Regional Supervisor an original and two copies of Form MMS-127; one of the copies must be a public information copy in accordance with §§ 250.186 and 250.197, and marked “Public Information.” You must also submit two copies of the supporting information, as listed in the table in § 250.1167. You must submit this information:
(a) Within 45 days after beginning production from the reservoir or discovering that it is sensitive;
(b) At least once during the calendar year, but you do not need to resubmit unrevised structure maps (§ 250.1167(a)(2)) or previously submitted well logs (§ 250.1167(c)(1));
(c) Within 45 days after you revise reservoir parameters; and
(d) Within 45 days after the Regional Supervisor classifies the reservoir as sensitive under § 250.1154(c).
(a) You must obtain approval from the Regional Supervisor before you start producing from a reservoir within a well that has any portion of the completed interval less than 500 feet from a unit or lease line. Submit to MMS the service fee listed in § 250.125, according to the instructions in § 250.126, and the supporting information, as listed in the table in § 250.1167, with your request. The Regional Supervisor will determine whether approval of your request will maximize ultimate recovery, avoid the waste of natural resources, or protect correlative rights. You do not need to obtain approval if the adjacent leases or units have the same unit, lease (record title and operating rights), and royalty interests as the lease or unit you plan to produce. You do not need to obtain approval if the adjacent block is unleased.
(b) You must notify the operator(s) of adjacent property(ies) that are within 500 feet of the completion, if the adjacent acreage is a leased block in the Federal OCS. You must provide the Regional Supervisor proof of the date of the notification. The operators of the adjacent properties have 30 days after receiving the notification to provide the Regional Supervisor letters of acceptance or objection. If an adjacent operator does not respond within 30
(1) The well name;
(2) The rectangular coordinates (x, y) of the location of the top and bottom of the completion or target completion referenced to the North American Datum 1983, and the subsea depths of the top and bottom of the completion or target completion;
(3) The distance from the completion or target completion to the unit or lease line at its nearest point; and
(4) A statement indicating whether or not it will be a high-capacity completion having a perforated or open hole interval greater than 150 feet measured depth.
(a) You must request and receive approval from the Regional Supervisor:
(1) Before producing gas-cap gas from each completion in an oil reservoir that is known to have an associated gas cap.
(2) To continue production from a well if the oil reservoir is not initially known to have an associated gas cap, but the oil well begins to show characteristics of a gas well.
(b) For either request, you must submit the service fee listed in § 250.125, according to the instructions in § 250.126, and the supporting information, as listed in the table in § 250.1167, with your request.
(c) The Regional Supervisor will determine whether your request maximizes ultimate recovery.
(a) Before you perforate a well, you must request and receive approval from the Regional Supervisor to commingle hydrocarbons produced from multiple reservoirs within a common wellbore. The Regional Supervisor will determine whether your request maximizes ultimate recovery. You must include the service fee listed in § 250.125, according to the instructions in § 250.126, and the supporting information, as listed in the table in § 250.1167, with your request.
(b) If one or more of the reservoirs proposed for commingling is a competitive reservoir, you must notify the operators of all leases that contain the reservoir that you intend to downhole commingle the reservoirs. Your request for approval of downhole commingling must include proof of the date of this notification. The notified operators have 30 days after notification to provide the Regional Supervisor with letters of acceptance or objection. If the notified operators do not respond within the specified period, the Regional Supervisor will assume the operators do not object and proceed with a decision.
(a) The Regional Supervisor may set a Maximum Production Rate (MPR) for a producing well completion, or set a Maximum Efficient Rate (MER) for a reservoir, or both, if the Regional Supervisor determines that an excessive production rate could harm ultimate recovery. An MPR or MER will be based on well tests and any limitations imposed by well and surface equipment, sand production, reservoir sensitivity, gas-oil and water-oil ratios, location of perforated intervals, and prudent operating practices.
(b) If the Regional Supervisor sets an MPR for a producing well completion and/or an MER for a reservoir, you may not exceed those rates except due to normal variations and fluctuations in production rates as set by the Regional Supervisor.
(a) You must request and receive approval from the Regional Supervisor to flare or vent natural gas at your facility, except in the following situations:
(b) Regardless of the requirements in paragraph (a) of this section, you must not flare or vent gas over the volume approved in your Development Operations Coordination Document (DOCD) or your Development and Production Plan (DPP).
(c) The Regional Supervisor may establish alternative approval procedures to cover situations when you cannot contact the MMS office, such as during non-office hours.
(d) The Regional Supervisor may specify a volume limit, or a shorter time limit than specified elsewhere in this part, in order to prevent air quality degradation or loss of reserves.
(e) If you flare or vent gas without the required approval, or if the Regional Supervisor determines that you were negligent or could have avoided flaring or venting the gas, the hydrocarbons will be considered avoidably lost or wasted. You must pay royalties on the loss or waste, according to part 202 of this title. You must value any gas or liquid hydrocarbons avoidably lost or wasted under the provisions of part 206 of this title.
(f) Fugitive emissions from valves, fittings, flanges, pressure relief valves or similar components do not require approval under this subpart unless specifically required by the Regional Supervisor.
You must request and receive approval from the Regional Supervisor to flare or vent gas for an extended period of time. The Regional Supervisor will
(a) You initiated an action which, when completed, will eliminate flaring and venting; or
(b) You submit to the Regional Supervisor an evaluation supported by engineering, geologic, and economic data indicating that the oil and gas produced from the well(s) will not economically support the facilities necessary to sell the gas or to use the gas on or for the benefit of the lease.
(a) You must request and receive approval from the Regional Supervisor to burn any produced liquid hydrocarbons. The Regional Supervisor may allow you to burn liquid hydrocarbons if you demonstrate that transporting them to market or re-injecting them is not technically feasible or poses a significant risk of harm to offshore personnel or the environment.
(b) If you burn liquid hydrocarbons without the required approval, or if the Regional Supervisor determines that you were negligent or could have avoided burning liquid hydrocarbons, the hydrocarbons will be considered avoidably lost or wasted. You must pay royalties on the loss or waste, according to part 202 of this title. You must value any liquid hydrocarbons avoidably lost or wasted under the provisions of part 206 of this title.
(a) If your facility processes more than an average of 2,000 bopd during May 2010, you must install flare/vent meters within 180 days after May 2010. If your facility processes more than an average of 2,000 bopd during a calendar month after May 2010, you must install flare/vent meters within 120 days after the end of the month in which the average amount of oil processed exceeds 2,000 bopd.
(1) You must notify the Regional Supervisor when your facility begins to process more than an average of 2,000 bopd in a calendar month;
(2) The flare/vent meters must measure all flared and vented gas within 5 percent accuracy;
(3) You must calibrate the meters regularly, in accordance with the manufacturer's recommendation, or at least once every year, whichever is shorter; and
(4) You must use and maintain the flare/vent meters for the life of the facility.
(b) You must report all hydrocarbons produced from a well completion, including all gas flared, gas vented, and liquid hydrocarbons burned, to Minerals Revenue Management on Form MMS-4054 (Oil and Gas Operations Report), in accordance with § 210.102 of this title.
(1) You must report the amount of gas flared and the amount of gas vented separately.
(2) You may classify and report gas used to operate equipment on the lease, such as gas used to power engines, instrument gas, and gas used to maintain pilot lights, as lease use gas.
(3) If flare/vent meters are required at one or more of your facilities, you must report the amount of gas flared and vented at each of those facilities separately from those facilities that do not require meters and separately from other facilities with meters.
(4) If flare/vent meters are not required at your facility:
(i) You may report the gas flared and vented on a lease or unit basis. Gas flared and vented from multiple facilities on a single lease or unit may be reported together.
(ii) If you choose to install meters, you may report the gas volume flared and vented according to the method specified in paragraph (b)(3) of this section.
(c) You must prepare and maintain records detailing gas flaring, gas venting, and liquid hydrocarbon burning for each facility for 6 years.
(1) You must maintain these records on the facility for at least the first 2
(2) After 2 years, you must maintain the records, allow MMS representatives to inspect the records upon request and provide copies to the Regional Supervisor upon request, but are not required to keep them on the facility.
(3) The records must include, at a minimum:
(i) Daily volumes of gas flared, gas vented, and liquid hydrocarbons burned;
(ii) Number of hours of gas flaring, gas venting, and liquid hydrocarbon burning, on a daily and monthly cumulative basis;
(iii) A list of the wells contributing to gas flaring, gas venting, and liquid hydrocarbon burning, along with gas-oil ratio data;
(iv) Reasons for gas flaring, gas venting, and liquid hydrocarbon burning; and
(v) Documentation of all required approvals.
(d) If your facility is required to have flare/vent meters:
(1) You must maintain the meter recordings for 6 years.
(i) You must keep these recordings on the facility for 2 years and have them available for inspection by MMS representatives.
(ii) After 2 years, you must maintain the recordings, allow MMS representatives to inspect the recordings upon request and provide copies to the Regional Supervisor upon request, but are not required to keep them on the facility.
(iii) These recordings must include the begin times, end times, and volumes for all flaring and venting incidents.
(2) You must maintain flare/vent meter calibration and maintenance records on the facility for 2 years.
(e) If your flaring or venting of gas, or burning of liquid hydrocarbons, required written or oral approval, you must submit documentation to the Regional Supervisor summarizing the location, dates, number of hours, and volumes of gas flared, gas vented, and liquid hydrocarbons burned under the approval.
(a) You may not vent gas containing H
(b) You may flare gas containing H
(1) For safety or air pollution prevention purposes, the Regional Supervisor may further restrict the flaring of gas containing H
(2) 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 you to conduct an air quality modeling analysis, under § 250.303, to determine the potential effect of facility emissions. The Regional Supervisor may require monitoring and reporting, or may restrict or prohibit flaring, under §§ 250.303 and 250.304.
(c) The Regional Supervisor may require you to submit monthly reports of flared and vented gas containing H
(1) The volume and duration of each flaring and venting occurrence;
(2) H
(3) The calculated amount of SO
(a) You must promptly initiate enhanced oil and gas recovery operations for all reservoirs where these operations would result in an increase in ultimate recovery of oil or gas under sound engineering and economic principles.
(b) Before initiating enhanced recovery operations, you must submit a proposed plan to the Regional Supervisor and receive approval for pressure maintenance, secondary or tertiary recovery, cycling, and similar recovery operations intended to increase the ultimate recovery of oil and gas from a reservoir. The proposed plan must include, for each project reservoir, a geologic and engineering overview, Form MMS-127 and supporting data as required in § 250.1167, and any additional information required by the Regional Supervisor.
(c) You must report to Minerals Revenue Management the volumes of oil, gas, or other substances injected, produced, or produced for a second time under § 210.102 of this title.
(a) For any development in the Alaska OCS Region, you must submit an annual reservoir management report to the Regional Supervisor. The report must contain information detailing the activities performed during the previous year and planned for the upcoming year that will:
(1) Provide for the prevention of waste;
(2) Provide for the protection of correlative rights; and
(3) Maximize ultimate recovery of oil and gas.
(b) If your development is jointly regulated by MMS and the State of Alaska, MMS and the Alaska Oil and Gas Conservation Commission will jointly determine appropriate reporting requirements to minimize or eliminate duplicate reporting requirements.
(c) Every time you are required to submit Form MMS-127 under § 250.1155, you must request an MER for each producing sensitive reservoir in the Alaska OCS Region, unless otherwise instructed by the Regional Supervisor.
You must submit the supporting information listed in the following table with the forms identified in columns 1 and 2 and for the approvals required under this subpart identified in columns 3 through 6:
(f) Depending on the type of approval requested, you must submit the appropriate payment of the service fee(s) listed in § 250.125, according to the instructions in § 250.126.
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 any changes to the previously-approved measurement and/or allocation procedures. Your application (which may also include any relevant gas measurement and surface commingling requests) must be accompanied by payment of the service fee listed in § 250.125. The service fees are divided into two levels based on complexity as shown in the following table.
(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. When a force majeure event precludes the required monthly meter proving, meters must be proved within 15 days after being returned to service. The meters must be proved monthly thereafter, 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
(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 250.198; 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 meter factor is determined by averaging the meter factors of the two runs; and
(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 operating allocation meters monthly if they measure 50 or more barrels per day per meter the previous month. When a force majeure event precludes the required monthly meter proving, meters must be proved within 15 days after being returned to service. The meters must be proved monthly thereafter; or
(4) Prove operating allocation meters quarterly if they measure less than 50 barrels per day per meter the previous month. When a force majeure event precludes the required quarterly meter proving, meters must be proved within 15 days after being returned to service. The meters must be proved quarterly thereafter;
(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 API MPMS as incorporated by reference in 30 CFR 250.198.
(a)
(b)
(1) Submit a written application to, and obtain approval from, the Regional
(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) Verify/calibrate operating meters monthly, but do not exceed 42 days between verifications/calibrations. When a force majeure event precludes the required monthly meter verification/calibration, meters must be verified/calibrated within 15 days after being returned to service. The meters must be verified/calibrated monthly thereafter, but do not exceed 42 days between meter verifications/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 any changes to the previously approved commingling procedures. Your application (which may also include any relevant liquid hydrocarbon and gas measurement requests) must be accompanied by payment of the service fee listed in § 250.125. The service fees are divided into two levels based on complexity, see table in § 250.1202(a)(1).
(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 60 days unless the Regional Supervisor approves a different frequency. When a force majeure event precludes the required well test within the prescribed 60 day period (or other frequency approved by the Regional Supervisor), wells must be tested within 15 days after being returned to production. Thereafter, well tests must be conducted at least once every 60 days (or other frequency approved by the Regional Supervisor);
(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.
(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 initiation of actual development drilling or production operations and that time period would extend beyond your lease's primary term or any extension under § 250.180, the unit operator must request and obtain MMS approval of a suspension of production under § 250.170 in order to keep the unit from terminating.
(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 with the Regional Supervisor for approval.
(d) You must pay the service fee listed in § 250.125 of this part with your request for a voluntary unitization proposal or the expansion of a previously approved voluntary unit to include additional acreage. Additionally, you must pay the service fee listed in § 250.125 with your request for unitization revision.
(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
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 $35,000 per day per violation.
At 76 FR 38296, June 30, 2011, § 250.1403 was revised, effective Aug. 1, 2011. For the convenience of the user, the revised text is set forth as follows:
The maximum civil penalty is $40,000 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 appropriate. The Reviewing Officer may administer oaths and issue subpoenas requiring witnesses to attend meetings, submit depositions, or produce evidence.
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 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 lease term for any Federal oil or gas lease, we may send you a Notice of Noncompliance informing 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 serve the Notice of Noncompliance by registered mail or personal service using the most current address on file as maintained by the BOEMRE Leasing Office in your respective Region.
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
(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 § 250.1472.
(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, or demonstrate financial solvency, using the standards and requirements as prescribed in 30 CFR 250.1490 through 250.1497, 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 § 250.1454. If you did not request a hearing on the record on the Notice of Noncompliance under § 250.1454, 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, 801 North Quincy Street, 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) Fail or refuse to permit lawful entry, inspection, or audit; or
(2) 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 any violation, without a period to correct, by issuing a Notice of Noncompliance and Civil Penalty explaining the violation, how to correct it, and the penalty assessment. We will serve the Notice of Noncompliance and Civil Penalty by registered mail or personal service using your address of record as specified under subpart H of part 1218.
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, 801 North Quincy Street, 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 on the record and a decision by the Administrative Law Judge under § 250.1472.
(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, or demonstrate financial solvency, using the standards and requirements as prescribed in 30 CFR 250.1490 through 250.1497, 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 § 250.1462. If you did not request a hearing on the record on the Notice of Noncompliance under § 250.1462, 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, 801 North Quincy, 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.
If you do not pay the penalty by the date required under § 250.1475(d), BOEMRE will assess you late payment interest on the penalty amount at the same rate interest is assessed under 30 CFR 1218.54.
If you request a hearing on the record under §§ 250.1454, 250.1456, 250.1462, or 250.1464, 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 §§ 250.1453 or 250.1461, if you do not request a hearing on the record under §§ 250.1454, 250.1456, 250.1462, or 250.1464
(b) If you request a hearing on the record under §§ 250.1454, 250.1456, 250.1462, or 250.1464, but you do not appeal the determination of the Administrative Law Judge to the Interior Board of Land Appeals under § 250.1473, 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 §§ 250.1454, 250.1456, 250.1462, or 250.1464;
(2) You received an Administrative Law Judge's decision under § 250.1472, if you obtained a stay of the accrual of penalties pending the hearing on the record under § 250.1455(b) or § 250.1463(b) and did not appeal the Administrative Law Judge's determination to the IBLA under § 250.1473;
(3) You received an IBLA decision under § 250.1473 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 § 250.1477.
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) BOEMRE 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 § 250.1474 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 § 250.1474. The amount of any penalty, as finally
If you commit an act for which a civil penalty is provided at 30 U.S.C. 1719(d) and § 250.1460(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.
(a) A BOEMRE-specified surety instrument must be in a form specified in BOEMRE instructions. BOEMRE will give you written information and standard forms for BOEMRE-specified surety instrument requirements.
(b) BOEMRE 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 BOEMRE with a minimum 1-year period of coverage subject to automatic renewal up to 5 years.
(a) The BOEMRE 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 BOEMRE-specified surety instrument must include the principal amount owed under the Notice of Noncompliance or Notice of Civil Penalty 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 BOEMRE bond-approving officer, up to 3 years of tax returns to BOEMRE using the U.S. Postal Service, private delivery, courier, or overnight delivery at:
(1) For Alaska OCS: Jeffrey Walker, RS/FO, BOEMRE Alaska OCS Region, 3801 Centerpoint Drive, Suite 500, Anchorage, AK 99503-5823,
(2) For Gulf of Mexico and Atlantic OCS: Joshua Joyce, Regional FARM Program Coordinator, BOEMRE Gulf of Mexico OCS Region, 1201 Elmwood Park Boulevard New Orleans, LA 70123-
(3) For Pacific OCS: Jaron Ming, Lead Leasing Specialist, BOEMRE Pacific OCS Region, 770 Paseo Camarillo, 2nd Floor, Camarillo, CA 93010,
(b) You must submit an audited consolidated balance sheet annually, and, if requested, additional annual tax returns on the date BOEMRE first determined that you demonstrated financial solvency as long as you have active appeals, or whenever BOEMRE requests.
(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 BOEMRE notifies you that you must redemonstrate financial solvency.
(a) The BOEMRE 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 30 CFR 250.1490 and 250.1491 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 30 CFR 250.1490 and 250.1491 for all orders you have appealed is less than $300 million, you must submit the following to BOEMRE by one of the methods in § 250.1495(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 250.126. You are 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 30 CFR 250.1490 and 250.1491;
(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 30 CFR 250.1490 and 250.1491;
(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 30 CFR 250.1490 and 250.1491 or pay the obligation.
(a) If you are presumptively financially solvent under § 250.1496(b), BOEMRE will determine your net worth as described under §§ 250.1496(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 § 250.1496(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 BOEMRE-specified surety instrument under §§ 250.1490 and 250.1491.
Terms used in this subpart have the following meaning:
At 75 FR 63376, Oct. 14, 2010, § 250.1500 was amended by adding a definition for “Well control”; however, the amendment could not be incorporated due to inaccurate amendatory instruction.
The goal of your training program must be safe and clean OCS operations. To accomplish this, you must ensure that your employees and contract personnel engaged in well control, deepwater well control, or production safety operations understand and can properly perform their duties.
(a) You must establish and implement a training program so that all of your employees are trained to competently perform their assigned well control, deepwater well control, and production safety duties. You must verify that your employees understand and can perform the assigned well control, deepwater well control, or production safety duties.
(b) If you conduct operations with a subsea BOP stack, your employees and contract personnel must be trained in deepwater well control. The trained employees and contract personnel must
(c) You must have a training plan that specifies the type, method(s), length, frequency, and content of the training for your employees. Your training plan must specify the method(s) of verifying employee understanding and performance. This plan must include at least the following information:
(1) Procedures for training employees in well control, deepwater well control, or production safety practices;
(2) Procedures for evaluating the training programs of your contractors;
(3) Procedures for verifying that all employees and contractor personnel engaged in well control, deepwater well control, or production safety operations can perform their assigned duties;
(4) Procedures for assessing the training needs of your employees on a periodic basis;
(5) Recordkeeping and documentation procedures; and
(6) Internal audit procedures.
(d) Upon request of the District Manager or Regional Supervisor, you must provide:
(1) Copies of training documentation for personnel involved in well control, deepwater well control, or production safety operations during the past 5 years; and
(2) A copy of your training plan.
You may use alternative training methods. These methods may include computer-based learning, films, or their equivalents. This training should be reinforced by appropriate demonstrations and “hands-on” training. Alternative training methods must be conducted according to, and meet the objectives of, your training plan.
You may get training from any source that meets the requirements of your training plan.
You determine the frequency of the training you provide your employees. You must do all of the following:
(a) Provide periodic training to ensure that employees maintain understanding of, and competency in, well control, deepwater well control, or production safety practices;
(b) Establish procedures to verify adequate retention of the knowledge and skills that employees need to perform their assigned well control, deepwater well control, or production safety duties; and
(c) Ensure that your contractors' training programs provide for periodic training and verification of well control, deepwater well control, or production safety knowledge and skills.
MMS may periodically assess your training program, using one or more of the methods in this section.
(a)
(b)
(c)
(d)
MMS or its authorized representative may test your employees or contract personnel at your worksite or at an onshore location. You and your contractors must:
(a) Allow MMS or its authorized representative to administer written or oral tests; and
(b) Identify personnel by current position, years of experience in present position, years of total oil field experience, and employer's name (e.g., operator, contractor, or sub-contractor company name).
If MMS or its authorized representative conducts, or requires you or your contractor to conduct hands-on, simulator, or other types of testing, you must:
(a) Allow MMS or its authorized representative to administer or witness the testing;
(b) Identify personnel by current position, years of experience in present position, years of total oil field experience, and employer's name (e.g., operator, contractor, or sub-contractor company name); and
(c) Pay for all costs associated with the testing, excluding salary and travel costs for MMS personnel.
If MMS determines that your training program is not in compliance, we may initiate one or more of the following enforcement actions:
(a) Issue an Incident of Noncompliance (INC);
(b) Require you to revise and submit to MMS your training plan to address identified deficiencies;
(c) Assess civil/criminal penalties; or
(d) Initiate disqualification procedures.
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 conducted for related purposes. Activities conducted for related purposes include, but are not limited to, production of other minerals, such as salt, for use in the exploration for or the development and production of sulphur. The lessee must have obtained the right to produce and/or use these other minerals.
(b) Lessees conducting sulphur operations in the OCS shall comply with the requirements of the applicable provisions of subparts A, B, C, I, J, M, N, O, and Q 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 Manager will determine whether a sulphur deposit has been defined that contains sulphur in paying quantities (
(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 Manager.
(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 Manager 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 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) 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 Manager to determine specific operating requirements, field rules may be established for drilling, well completion, or well workover on the District Manager'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 Manager 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 stresses imposed by tensile, compressive, and buckling loads; burst and collapse pressures; thermal effects; and combinations thereof. Safety factors in the drilling and casing program designs shall be of sufficient magnitude to provide well control during drilling and to assure safe operations for the life of the well.
(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 Manager 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 Manager. 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
(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. Accumulator regulators supplied by rig air that do not have a secondary source of pneumatic supply must 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 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 Manager;
(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 Manager.
(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 Manager. Annular type BOP's shall be pressure tested with water to 70 percent of rated working pressure or as otherwise approved by the District Manager.
(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 date, time, 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) 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 Manager. 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 Manager.
Well-control drills shall be conducted for each drilling crew in accordance with the requirements set forth in
(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) The diverter system shall be equipped with remote-control valves in the flow 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 valves shall be installed in any part of a 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. Flexible hose may be used for diversion 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 vibrations. All diverter control equipment and lines shall be protected from physical damage from thrown and falling objects.
(c) 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.
(d) 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 § 250.455 through § 250.459 of this part, except that the installation of an operable degasser in the mud system as required in § 250.456(g) 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 Manager 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) Before drilling a well under an approved Exploration Plan, Development and Production Plan, or Development Operations Coordination Document, you must file Form MMS-123, APD, with the District Manager for approval. The submission of your APD must be accompanied by payment of the service fee listed in § 250.125. Before starting operations, you must receive written approval from the District Manager unless you received oral approval under § 250.140.
(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 Manager 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
(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 Manager.
(d) Public information copies of the APD shall be submitted in accordance with § 250.186 of this part.
(a) You must submit requests for changes in plans, changes in major drilling equipment, proposals to deepen, sidetrack, complete, workover, or plug back a well, or engage in similar activities to the District Manager on Form MMS-124, Application for Permit to Modify (APM). The submission of your APM must be accompanied by payment of the service fee listed in § 250.125. Before starting operations associated with the change, you must receive written approval from the District Manager unless you received oral approval under § 250.140.
(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 Manager. 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 Manager 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 Manager duplicate copies of the records of all
(c) Upon request by the District Manager or Regional 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 Manager. 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 Manager in duplicate as soon as available but not later than 30 days after completion of such operations for each well.
(e) If the District Manager determines that circumstances warrant, the lessee shall submit any other reports and records of operations in the manner and form prescribed by the District Manager.
(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 Manager. Approval for such operations shall be requested on Form MMS-124. Approvals by the District Manager 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 Manager.
(2) Within 30 days after completing the well-workover operation, except routine operations, Form MMS-124 shall be submitted to the District Manager 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 continuously 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
(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 Manager. Annular type BOP's shall be pressure tested with water to 70 percent of rated working pressure or as otherwise approved by the District Manager.
(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 Manager. 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 Manager.
(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,
(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 (incorporated by reference as specified in § 250.198), 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 Manager 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, incorporated by reference as specified in § 250.198) and the related Safety Analysis Function Evaluation chart (API RP 14C, subsection 4.3c, incorporated by reference as specified in § 250.198).
(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 (incorporated by reference as specified in § 250.198), 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
(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 (incorporated by reference as specified in 30 CFR 250.198). 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 Manager. 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
(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 Manager;
(iii) A firefighting system using chemicals may be used in lieu of a water system if the District Manager 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-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 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 Manager may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.
(v) Fire- and gas-detection systems must be an approved type, designed and installed according to API RP 14C, API RP 14G, and either API RP 14F or API RP 14FZ (the preceding four documents incorporated by reference as specified in § 250.198).
(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 (excluding electronic pressure transmitters and level sensors) must be inspected and tested at least once each calendar month, but at no time may 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) The following electronic pressure transmitters and level sensors must be inspected and tested at least once every 3 months, but at no time may more than 120 days elapse between tests:
(i) All PSH or PSL, and
(ii) All LSH and LSL controls.
(4) All pumps for firewater systems shall be inspected and operated weekly.
(5) 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.
(6) Prior to the commencement of production, the lessee shall notify the District Manager when the lessee is ready to conduct a preproduction test and inspection of the safety system. The lessee shall also notify the District Manager 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 the safety requirements of the operations to be performed; possible hazards to be encountered; and general safety considerations to be taken to protect personnel, equipment, and the environment. Date and time of safety meetings shall be recorded and available for MMS review.
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
(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
(a)
(1) Ending oil, gas, or sulphur operations; and
(2) Returning the lease or pipeline right-of-way to a condition that meets the requirements of regulations of MMS and other agencies that have jurisdiction over decommissioning activities.
(b)
(c)
(a) Lessees and owners of operating rights are jointly and severally responsible for meeting decommissioning obligations for facilities on leases, including the obligations related to lease-term pipelines, as the obligations accrue and until each obligation is met.
(b) All holders of a right-of-way are jointly and severally liable for meeting decommissioning obligations for facilities on their right-of-way, including right-of-way pipelines, as the obligations accrue and until each obligation is met.
(c) In this subpart, the terms “you” or “I” refer to lessees and owners of operating rights, as to facilities installed under the authority of a lease, and to right-of-way holders as to facilities installed under the authority of a right-of-way.
You accrue decommissioning obligations when you do any of the following:
(a) Drill a well;
(b) Install a platform, pipeline, or other facility;
(c) Create an obstruction to other users of the OCS;
(d) Are or become a lessee or the owner of operating rights of a lease on which there is a well that has not been permanently plugged according to this subpart, a platform, a lease term pipeline, or other facility, or an obstruction;
(e) Are or become the holder of a pipeline right-of-way on which there is a pipeline, platform, or other facility, or an obstruction; or
(f) Re-enter a well that was previously plugged according to this subpart.
When your facilities are no longer useful for operations, you must:
(a) Get approval from the appropriate District Manager before decommissioning wells and from the Regional Supervisor before decommissioning platforms and pipelines or other facilities;
(b) Permanently plug all wells;
(c) Remove all platforms and other facilities, except as provided in sections 1725(a) and 1730.
(d) Decommission all pipelines;
(e) Clear the seafloor of all obstructions created by your lease and pipeline right-of-way operations; and
(f) Conduct all decommissioning activities in a manner that is safe, does not unreasonably interfere with other uses of the OCS, and does not cause undue or serious harm or damage to the human, marine, or coastal environment.
You must submit decommissioning applications and receive approval and submit subsequent reports according to the table in this section.
You must permanently plug all wells on a lease within 1 year after the lease terminates.
MMS will order you to permanently plug a well if that well:
(a) Poses a hazard to safety or the environment; or
(b) Is not useful for lease operations and is not capable of oil, gas, or sulphur production in paying quantities.
Before you permanently plug a well or zone, you must submit form MMS-124, Application for Permit to Modify, to the appropriate District Manager and receive approval. A request for approval must contain the following information:
(a) The reason you are plugging the well (or zone), for completions with production amounts specified by the Regional Supervisor, along with substantiating information demonstrating its lack of capacity for further profitable production of oil, gas, or sulfur;
(b) Recent well test data and pressure data, if available;
(c) Maximum possible surface pressure, and how it was determined;
(d) Type and weight of well-control fluid you will use;
(e) A description of the work;
(f) A current and proposed well schematic and description that includes:
(1) Well depth;
(2) All perforated intervals that have not been plugged;
(3) Casing and tubing depths and details;
(4) Subsurface equipment;
(5) Estimated tops of cement (and the basis of the estimate) in each casing annulus;
(6) Plug locations;
(7) Plug types;
(8) Plug lengths;
(9) Properties of mud and cement to be used;
(10) Perforating and casing cutting plans;
(11) Plug testing plans;
(12) Casing removal (including information on explosives, if used);
(13) Proposed casing removal depth; and
(14) Your plans to protect archaeological and sensitive biological features, including anchor damage during plugging operations, a brief assessment of the environmental impacts of the plugging operations, and the procedures and mitigation measures you will take to minimize such impacts; and
(g) Certification by a Registered Professional Engineer of the well abandonment design and procedures; that there will be at least two independent tested barriers, including one mechanical barrier, across each flow path during abandonment activities; and that the plug meets the requirements in the table in § 250.1715. The Registered Professional Engineer must be registered in a State in the United States. You must submit this certification with your APM (Form MMS-124).
You must notify the appropriate District Manager at least 48 hours before beginning operations to permanently plug a well.
You must ensure that all well plugs:
(a) Provide downhole isolation of hydrocarbon and sulphur zones;
(b) Protect freshwater aquifers; and
(c) Prevent migration of formation fluids within the wellbore or to the seafloor.
(a) You must permanently plug wells according to the table in this section. The District Manager may require additional well plugs as necessary.
(b) You must test the first plug below the surface plug and all plugs in lost circulation areas that are in open hole. The plug must pass one of the following tests to verify plug integrity:
(1) A pipe weight of at least 15,000 pounds on the plug; or
(2) A pump pressure of at least 1,000 pounds per square inch. Ensure that the pressure does not drop more than 10 percent in 15 minutes. The District Manager may require you to tests other plug(s).
(a) Unless the District Manager approves an alternate depth under paragraph (b) of this section, you must remove all wellheads and casings to at least 15 feet below the mud line.
(b) The District Manager may approve an alternate removal depth if:
(1) The wellhead or casing would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or
(2) You determine, and MMS concurs, that you must use divers, and the seafloor sediment stability poses safety concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).
Within 30 days after you permanently plug a well, you must submit form MMS-124, Application for Permit to Modify (subsequent report), to the appropriate District Manager, and include the following information:
(a) Information included in § 250.1712 with a final well schematic;
(b) Description of the plugging work;
(c) Nature and quantities of material used in the plugs; and
(d) If you cut and pulled any casing string, the following information:
(1) A description of the methods used (including information on explosives, if used);
(2) Size and amount of casing removed; and
(3) Casing removal depth.
You may temporarily abandon a well when it is necessary for proper development and production of a lease. To temporarily abandon a well, you must do all of the following:
(a) Submit form MMS-124, Application for Permit to Modify, and the applicable information required by § 250.1712 to the appropriate District Manager and receive approval;
(b) Adhere to the plugging and testing requirements for permanently plugged wells listed in the table in § 250.1715, except for § 250.1715 (a)(8). You do not need to sever the casings, remove the wellhead, or clear the site;
(c) Set a bridge plug or a cement plug at least 100-feet long 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;
(d) Set a retrievable or a permanent-type bridge plug or a cement plug at least 100 feet long in the inner-most casing. The top of the bridge plug or cement plug must be no more than 1,000 feet below the mud line. MMS may consider approving alternate requirements for subsea wells case-by-case;
(e) Identify and report subsea wellheads, casing stubs, or other obstructions that extend above the mud line according to U.S. Coast Guard (USCG) requirements;
(f) Except in water depths greater than 300 feet, protect subsea wellheads, casing stubs, mud line suspensions, or other obstructions remaining above the seafloor by using one of the following methods, as approved by the District Manager or Regional Supervisor:
(1) A caisson designed according to 30 CFR 250, subpart I, and equipped with aids to navigation;
(2) A jacket designed according to 30 CFR 250, subpart I, and equipped with aids to navigation; or
(3) A subsea protective device that meets the requirements in § 250.1722.
(g) Within 30 days after you temporarily plug a well, you must submit form MMS-124, Application for Permit to Modify (subsequent report), and include the following information:
(1) Information included in § 250.1712 with a well schematic;
(2) Information required by § 250.1717(b), (c), and (d); and
(3) A description of any remaining subsea wellheads, casing stubs, mudline suspension equipment, or other obstructions that extend above the seafloor; and
(h) Submit certification by a Registered Professional Engineer of the well abandonment design and procedures; that there will be at least two independent tested barriers, including one mechanical barrier, across each flow path during abandonment activities; and that the plug meets the requirements in the table in § 250.1715. The Registered Professional Engineer must be registered in a State in the United States. You must submit this
If you install a subsea protective device under § 250.1721(f)(3), you must install it in a manner that allows fishing gear to pass over the obstruction without damage to the obstruction, the protective device, or the fishing gear.
(a) Use form MMS-124, Application for Permit to Modify to request approval from the appropriate District Manager to install a subsea protective device.
(b) The protective device may not extend more than 10 feet above the seafloor (unless MMS approves otherwise).
(c) You must trawl over the protective device when you install it (adhere to the requirements at § 250.1741 (d) through (h)). If the trawl does not pass over the protective device or causes damage to it, you must notify the appropriate District Manager within 5 days and perform remedial action within 30 days of the trawl;
(d) Within 30 days after you complete the trawling test described in paragraph (c) of this section, submit a report to the appropriate District Manager using form MMS-124, Application for Permit to Modify, that includes the following:
(1) The date(s) the trawling test was performed and the vessel that was used;
(2) A plat at an appropriate scale showing the trawl lines;
(3) A description of the trawling operation and the net(s) that were used;
(4) An estimate by the trawling contractor of the seafloor penetration depth achieved by the trawl;
(5) A summary of the results of the trawling test including a discussion of any snags and interruptions, a description of any damage to the protective covering, the casing stub or mud line suspension equipment, or the trawl, and a discussion of any snag removals requiring diver assistance; and
(6) A letter signed by your authorized representative stating that he/she witnessed the trawling test.
(e) If a temporarily abandoned well is protected by a subsea device installed in a water depth less than 100 feet, mark the site with a buoy installed according to the USCG requirements.
(f) Provide annual reports to the Regional Supervisor describing your plans to either re-enter and complete the well or to permanently plug the well.
(g) Ensure that all subsea wellheads, casing stubs, mud line suspensions, or other obstructions in water depths less than 300 feet remain protected.
(1) To confirm that the subsea protective covering remains properly installed, either conduct a visual inspection or perform a trawl test at least annually.
(2) If the inspection reveals that a casing stub or mud line suspension is no longer properly protected, or if the trawl does not pass over the subsea protective covering without causing damage to the covering, the casing stub or mud line suspension equipment, or the trawl, notify the appropriate District Manager within 5 days, and perform the necessary remedial work within 30 days of discovery of the problem.
(3) In your annual report required by paragraph (f) of this section, include the inspection date, results, and method used and a description of any remedial work you will perform or have performed.
(h) You may request approval to waive the trawling test required by paragraph (c) of this section if you plan to use either:
(1) A buoy with automatic tracking capabilities installed and maintained according to USCG requirements at 33 CFR part 67 (or its successor); or
(2) A design and installation method that has been proven successful by trawl testing of previous protective devices of the same design and installed in areas with similar bottom conditions.
If you or MMS determines that continued maintenance of a well in a temporary abandoned status is not necessary for the proper development or production of a lease, you must:
(a) Promptly and permanently plug the well according to § 250.1715;
(b) Remove any casing stub or mud line suspension equipment and any subsea protective covering. You must submit a request for approval to perform such work to the appropriate District Manager using form MMS-124, Application for Permit to Modify; and
(c) Clear the well site according to § 250.1740 through § 250.1742.
(a) You must remove all platforms and other facilities within 1 year after the lease or pipeline right-of-way terminates, unless you receive approval to maintain the structure to conduct other activities. Platforms include production platforms, well jackets, single-well caissons, and pipeline accessory platforms. Other activities include those supporting OCS oil and gas production and transportation, as well as other energy-related or marine-related uses (including LNG) for which adequate financial assurance for decommissioning has been provided to a Federal agency which has given MMS a commitment that it has and will exercise authority to compel the performance of decommissioning within a time following cessation of the new use acceptable to MMS. The approval will specify:
(1) Whether you must continue to maintain any financial assurance for decommissioning; and
(2) Whether, and under what circumstances, you must perform any decommissioning not performed by the new facility owner/user.
(b) Before you may remove a platform or other facility, you must submit a final removal application to the Regional Supervisor for approval and include the information listed in § 250.1727.
(c) You must remove a platform or other facility according to the approved application.
(d) You must flush all production risers with seawater before you remove them.
(e) You must notify the Regional Supervisor at least 48 hours before you begin the removal operations.
An initial platform removal application is required only for leases and pipeline rights-of-way in the Pacific OCS Region or the Alaska OCS Region. It must include the following information:
(a) Platform or other facility removal procedures, including the types of vessels and equipment you will use;
(b) Facilities (including pipelines) you plan to remove or leave in place;
(c) Platform or other facility transportation and disposal plans;
(d) Plans to protect marine life and the environment during decommissioning operations, including a brief assessment of the environmental impacts of the operations, and procedures and mitigation measures that you will take to minimize the impacts; and
(e) A projected decommissioning schedule.
You must submit to the Regional Supervisor, a final application for approval to remove a platform or other facility. Your application must be accompanied by payment of the service fee listed in § 250.125. If you are proposing to use explosives, provide three copies of the application. If you are not proposing to use explosives, provide two copies of the application. Include the following information in the final removal application, as applicable:
(a) Identification of the applicant including:
(1) Lease operator/pipeline right-of-way holder;
(2) Address;
(3) Contact person and telephone number; and
(4) Shore base.
(b) Identification of the structure you are removing including:
(1) Platform Name/MMS Complex ID Number;
(2) Location (lease/right-of-way, area, block, and block coordinates);
(3) Date installed (year);
(4) Proposed date of removal (Month/Year); and
(5) Water depth.
(c) Description of the structure you are removing including:
(1) Configuration (attach a photograph or a diagram);
(2) Size;
(3) Number of legs/casings/pilings;
(4) Diameter and wall thickness of legs/casings/pilings;
(5) Whether piles are grouted inside or outside;
(6) Brief description of soil composition and condition;
(7) The sizes and weights of the jacket, topsides (by module), conductors, and pilings; and
(8) The maximum removal lift weight and estimated number of main lifts to remove the structure.
(d) A description, including anchor pattern, of the vessel(s) you will use to remove the structure.
(e) Identification of the purpose, including:
(1) Lease expiration/right-of-way relinquishment date; and
(2) Reason for removing the structure.
(f) A description of the removal method, including:
(1) A brief description of the method you will use;
(2) If you are using explosives, the following:
(i) Type of explosives;
(ii) Number and sizes of charges;
(iii) Whether you are using single shot or multiple shots;
(iv) If multiple shots, the sequence and timing of detonations;
(v) Whether you are using a bulk or shaped charge;
(vi) Depth of detonation below the mud line; and
(vii) Whether you are placing the explosives inside or outside of the pilings;
(3) If you will use divers or acoustic devices to conduct a pre-removal survey to detect the presence of turtles and marine mammals, a description of the proposed detection method; and
(4) A statement whether or not you will use transducers to measure the pressure and impulse of the detonations.
(g) Your plans for transportation and disposal (including as an artificial reef) or salvage of the removed platform.
(h) If available, the results of any recent biological surveys conducted in the vicinity of the structure and recent observations of turtles or marine mammals at the structure site.
(i) Your plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures you will take to minimize such impacts.
(j) A statement whether or not you will use divers to survey the area after removal to determine any effects on marine life.
(a) Unless the Regional Supervisor approves an alternate depth under paragraph (b) of this section, you must remove all platforms and other facilities (including templates and pilings) to at least 15 feet below the mud line.
(b) The Regional Supervisor may approve an alternate removal depth if:
(1) The remaining structure would not become an obstruction to other users of the seafloor or area, and geotechnical and other information you provide demonstrate that erosional processes capable of exposing the obstructions are not expected; or
(2) You determine, and MMS concurs, that you must use divers and the seafloor sediment stability poses safety concerns; or
(3) The water depth is greater than 800 meters (2,624 feet).
Within 30 days after you remove a platform or other facility, you must submit a written report to the Regional Supervisor that includes the following:
(a) A summary of the removal operation including the date it was completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that certifies that the types and amount of explosives you used in removing the platform or other facility were consistent with those set forth in the approved removal application.
The Regional Supervisor may grant a departure from the requirement to remove a platform or other facility by approving partial structure removal or toppling in place for conversion to an artificial reef if you meet the following conditions:
(a) The structure becomes part of a State artificial reef program, and the responsible State agency acquires a permit from the U.S. Army Corps of Engineers and accepts title and liability for the structure; and
(b) You satisfy any U.S. Coast Guard (USCG) navigational requirements for the structure.
(a) The holder of an Alternate Use RUE issued under part 285 of this subchapter is responsible for all decommissioning obligations that accrue following the issuance of the Alternate Use RUE and which pertain to the Alternate Use RUE. See 30 CFR part 285, subpart J, for additional information concerning the decommissioning responsibilities of an Alternate Use RUE grant holder.
(b) The lessee under the lease originally issued under 30 CFR part 256 will remain responsible for decommissioning obligations that accrued before issuance of the Alternate Use RUE, as well as for decommissioning obligations that accrue following issuance of the Alternate Use RUE to the extent associated with continued activities authorized under this part.
(c) If a lease issued under 30 CFR part 256 is cancelled or otherwise terminated under any provision of this subchapter, the lessee, upon our approval, may defer removal of any OCS facility within the lease area that is subject to an Alternate Use RUE. If we elect to grant such a deferral, the lessee remains responsible for removing the facility upon termination of the Alternate Use RUE and will be required to retain sufficient bonding or other financial assurances to ensure that the structure is removed or otherwise decommissioned in accordance with the provisions of this subpart.
Within 60 days after you permanently plug a well or remove a platform or other facility, you must verify that the site is clear of obstructions by using one of the following methods:
(a) For a well site, you must either:
(1) Drag a trawl over the site;
(2) Scan across the location using sonar equipment;
(3) Inspect the site using a diver;
(4) Videotape the site using a camera on a remotely operated vehicle (ROV); or
(5) Use another method approved by the District Manager if the particular site conditions warrant.
(b) For a platform or other facility site in water depths less than 300 feet, you must drag a trawl over the site.
(c) For a platform or other facility site in water depths 300 feet or more, you must either:
(1) Drag a trawl over the site;
(2) Scan across the site using sonar equipment; or
(3) Use another method approved by the Regional Supervisor if the particular site conditions warrant.
If you drag a trawl across the site in accordance with § 250.1740, you must meet all of the requirements of this section.
(a) You must drag the trawl in a grid-like pattern as shown in the following table:
(b) You must trawl 100 percent of the limits described in paragraph (a) of this section in two directions.
(c) You must mark the area to be cleared as a hazard to navigation according to USCG requirements until you complete the site clearance procedures.
(d) You must use a trawling vessel equipped with a calibrated navigational positioning system capable of providing position accuracy of ±30 feet.
(e) You must use a trawling net that is representative of those used in the commercial fishing industry (one that has a net strength equal or greater than that provided by No. 18 twine).
(f) You must ensure that you trawl no closer than 300 feet from a shipwreck, and 500 feet from a sensitive biological feature.
(g) If you trawl near an active pipeline, you must meet the requirements in the following table:
(h) You must ensure that any trawling contractor you may use:
(1) Has no corporate or other financial ties to you; and
(2) Has a valid commercial trawling license for both the vessel and its captain.
If you do not trawl a site, you can verify that the site is clear of obstructions by using any of the methods shown in the following table:
(a) For a well site, you must submit to the appropriate District Manager within 30 days after you complete the verification activities a form MMS-124, Application for Permit to Modify, to include the following information:
(1) A signed certification that the well site area is cleared of all obstructions;
(2) The date the verification work was performed and the vessel used;
(3) The extent of the area surveyed;
(4) The survey method used;
(5) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no objects were recovered; and
(6) A post-trawling job plot or map showing the trawled area.
(b) For a platform or other facility site, you must submit the following information to the appropriate Regional Supervisor within 30 days after you complete the verification activities:
(1) A letter signed by an authorized company official certifying that the platform or other facility site area is cleared of all obstructions and that a company representative witnessed the verification activities;
(2) A letter signed by an authorized official of the company that performed the verification work for you certifying that they cleared the platform or other facility site area of all obstructions;
(3) The date the verification work was performed and the vessel used;
(4) The extent of the area surveyed;
(5) The survey method used;
(6) The results of the survey, including a list of any debris removed or a statement from the trawling contractor that no objects were recovered; and
(7) A post-trawling job plot or map showing the trawled area.
You may decommission a pipeline in place when the Regional Supervisor determines that the pipeline does not constitute a hazard (obstruction) to navigation and commercial fishing operations, unduly interfere with other uses of the OCS, or have adverse environmental effects.
You must do the following to decommission a pipeline in place:
(a) Submit a pipeline decommissioning application in triplicate to the Regional Supervisor for approval. Your application must be accompanied by payment of the service fee listed in § 250.125. Your application must include the following information:
(1) Reason for the operation;
(2) Proposed decommissioning procedures;
(3) Length (feet) of segment to be decommissioned; and
(4) Length (feet) of segment remaining.
(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical;
(c) Flush the pipeline;
(d) Fill the pipeline with seawater;
(e) Cut and plug each end of the pipeline;
(f) Bury each end of the pipeline at least 3 feet below the seafloor or cover each end with protective concrete mats, if required by the Regional Supervisor; and
(g) Remove all pipeline valves and other fittings that could unduly interfere with other uses of the OCS.
Before removing a pipeline, you must:
(a) Submit a pipeline removal application in triplicate to the Regional Supervisor for approval. Your application must be accompanied by payment of the service fee listed in § 250.125. Your application must include the following information:
(1) Proposed removal procedures;
(2) If the Regional Supervisor requires it, a description, including anchor pattern(s), of the vessel(s) you will use to remove the pipeline;
(3) Length (feet) to be removed;
(4) Length (feet) of the segment that will remain in place;
(5) Plans for transportation of the removed pipe for disposal or salvage;
(6) Plans to protect archaeological and sensitive biological features during removal operations, including a brief assessment of the environmental impacts of the removal operations and procedures and mitigation measures that you will take to minimize such impacts; and
(7) Projected removal schedule and duration.
(b) Pig the pipeline, unless the Regional Supervisor determines that pigging is not practical; and
(c) Flush the pipeline.
Within 30 days after you decommission a pipeline, you must submit a written report to the Regional Supervisor that includes the following:
(a) A summary of the decommissioning operation including the date it was completed;
(b) A description of any mitigation measures you took; and
(c) A statement signed by your authorized representative that certifies that the pipeline was decommissioned according to the approved application.
You must remove a pipeline decommissioned in place if the Regional Supervisor determines that the pipeline is an obstruction.
You must develop, implement, and maintain a safety and environmental management system (SEMS) program. Your SEMS program must address the elements described in § 250.1902, American Petroleum Institute's Recommended Practice for Development of a Safety and Environmental Management Program for Offshore Operations and Facilities (API RP 75) (incorporated by reference as specified in § 250.198), and other requirements as identified in this subpart.
(a) You must comply with the provisions of this subpart and have your SEMS program in effect on or before November 15, 2011, except for the submission of Form MMS-131 as required in § 250.1929.
(b) You must submit Form MMS-131 on an annual basis beginning March 31, 2011.
(c) If there are any conflicts between the requirements of this subpart and API RP 75 (incorporated by reference as specified in § 250.198), you must follow the requirements of this subpart.
(d) Nothing in this subpart affects safety or other matters under the jurisdiction of the Coast Guard.
The goal of your SEMS program is to promote safety and environmental protection by ensuring all personnel aboard a facility are complying with the policies and procedures identified in your SEMS.
(a) To accomplish this goal, you must ensure that your SEMS program identifies, addresses, and manages safety, environmental hazards, and impacts during the design, construction, start-up, operation, inspection, and maintenance of all new and existing facilities, including mobile offshore drilling units (MODU) while under BOEMRE jurisdiction and Department of Interior (DOI) regulated pipelines.
(b) All personnel involved with your SEMS program must be trained to have the skills and knowledge to perform their assigned duties.
You must have a properly documented SEMS program in place and make it available to BOEMRE upon request as required by § 250.1924(b).
(a) Your SEMS program must meet the minimum criteria outlined in this subpart, including the following SEMS program elements:
(1) General (
(2) Safety and Environmental Information (
(3) Hazards Analysis (
(4) Management of Change (
(5) Operating Procedures (
(6) Safe Work Practices (
(7) Training (
(8) Mechanical Integrity (Assurance of Quality and Mechanical Integrity of Critical Equipment) (
(9) Pre-startup Review (
(10) Emergency Response and Control (
(11) Investigation of Incidents (
(12) Auditing (Audit of Safety and Environmental Management Program Elements) (
(13) Recordkeeping (Records and Documentation) and additional BOEMRE requirements (
(b) You must also include a job safety analysis (JSA) for OCS activities identified or discussed in your SEMS program (
(c) Your SEMS program must meet or exceed the standards of safety and environmental protection of API RP 75 (incorporated by reference as specified in § 250.198).
Definitions listed in this section apply to this subpart and supersede definitions in API RP 75, Appendices D and E (incorporated by reference as specified in § 250.198).
The effect of incorporation by reference of a document into the regulations in this part is that the incorporated document is a requirement. When a section in this part incorporates all of a document, you are responsible for complying with the provisions of that entire document, except to the extent that section provides otherwise. If any incorporated document uses the word “should
You, through your management, must require that the program elements discussed in API RP 75 (incorporated by reference as specified in § 250.198) and in this subpart are properly documented and are available at field and office locations, as appropriate for each program element. You,
(a) Establish goals and performance measures, demand accountability for implementation, and provide necessary resources for carrying out an effective SEMS program.
(b) Appoint management representatives who are responsible for establishing, implementing and maintaining an effective SEMS program.
(c) Designate specific management representatives who are responsible for reporting to management on the performance of the SEMS program.
(d) At intervals specified in the SEMS program and at least annually, review the SEMS program to determine if it continues to be suitable, adequate and effective (by addressing the possible need for changes to policy, objectives, and other elements of the program in light of program audit results, changing circumstances and the commitment to continual improvement) and document the observations, conclusions and recommendations of that review.
(e) Develop and endorse a written description of your safety and environmental policies and organizational structure that define responsibilities, authorities, and lines of communication required to implement the SEMS program.
(f) Utilize personnel with expertise in identifying safety hazards, environmental impacts, optimizing operations, developing safe work practices, developing training programs and investigating incidents.
(g) Ensure that facilities are designed, constructed, maintained, monitored, and operated in a manner compatible with applicable industry codes, consensus standards, and generally accepted practice as well as in compliance with all applicable governmental regulations.
(h) Ensure that management of safety hazards and environmental impacts is an integral part of the design, construction, maintenance, operation, and monitoring of each facility.
(i) Ensure that suitably trained and qualified personnel are employed to carry out all aspects of the SEMS program.
(j) Ensure that the SEMS program is maintained and kept up to date by means of periodic audits to ensure effective performance.
(a) You must require that SEMS program safety and environmental information be developed and maintained for any facility that is subject to the SEMS program.
(b) SEMS program safety and environmental information must include:
(1) Information that provides the basis for implementing all SEMS program elements, including the requirements of hazard analysis (§ 250.1911);
(2) process design information including, as appropriate, a simplified process flow diagram and acceptable upper and lower limits, where applicable, for items such as temperature, pressure, flow and composition; and
(3) mechanical design information including, as appropriate, piping and instrument diagrams; electrical area classifications; equipment arrangement drawings; design basis of the relief system; description of alarm, shutdown, and interlock systems; description of well control systems; and design basis for passive and active fire protection features and systems and emergency evacuation procedures.
You must ensure the development and implementation of a hazards analysis (facility level) and a job safety analysis (operations/task level) for all of your facilities. For this subpart, facilities include all types of offshore structures permanently or temporarily attached to the seabed (
(a) Hazards Analysis (facility level). For a hazards analysis (facility level), you must perform an initial hazards analysis on each facility on or before November 15, 2011. The hazards analysis must be appropriate to the complexity of the operation and must identify, evaluate, and manage the hazards involved in the operation.
(1) The hazards analysis must address the following:
(i) Hazards of the operation;
(ii) Previous incidents related to the operation you are evaluating, including any incident in which you were issued an Incident of Noncompliance or a civil or criminal penalty;
(iii) Control technology applicable to the operation your hazards analysis is evaluating; and
(iv) A qualitative evaluation of the possible safety and health effects on employees, and potential impacts to the human and marine environments, which may result if the control technology fails.
(2) The hazards analysis must be performed by a person(s) with experience in the operations being evaluated. These individuals also need to be experienced in the hazards analysis methodologies being employed.
(3) You should assure that the recommendations in the hazards analysis are resolved and that the resolution is documented.
(b) Job Safety Analysis (JSA). You must develop and implement a JSA for OCS activities identified or discussed in your SEMS program.
(1) You must keep a copy of the most recent JSA (operations/task level) at the job site and it must be readily accessible to employees.
(2) Your JSA must identify, analyze, and record:
(i) The steps involved in performing a specific job;
(ii) the existing or potential safety and health hazards associated with each step; and
(iii) the recommended action(s)/procedure(s) that will eliminate or reduce these hazards and the risk of a workplace injury or illness.
(3) The supervisor of the person in charge of the task must approve the JSA prior to the commencement of the work.
(a) You must develop and implement written management of change procedures for modifications associated with the following:
(1) Equipment,
(2) Operating procedures,
(3) Personnel changes (including contractors),
(4) Materials, and
(5) Operating conditions.
(b) Management of change procedures do not apply to situations involving replacement in kind (such as, replacement of one component by another component with the same performance capabilities).
(c) You must review all changes prior to their implementation.
(d) The following items must be included in your management of change procedures:
(1) The technical basis for the change;
(2) Impact of the change on safety, health, and the coastal and marine environments;
(3) Necessary time period to implement the change; and
(4) Management approval procedures for the change.
(e) Employees, including contractors whose job tasks will be affected by a change in the operation, must be informed of, and trained in, the change prior to startup of the process or affected part of the operation; and
(f) If a management of change results in a change in the operating procedures of your SEMS program, such changes must be documented and dated.
(a) You must develop and implement written operating procedures that provide instructions for conducting safe and environmentally sound activities involved in each operation addressed in your SEMS program. These procedures must include the job title and reporting relationship of the person or persons responsible for each of the facility's operating areas and address the following:
(1) Initial startup;
(2) Normal operations;
(3) All emergency operations (including but not limited to medical evacuations, weather-related evacuations and emergency shutdown operations);
(4) Normal shutdown;
(5) Startup following a turnaround, or after an emergency shutdown;
(6) Bypassing and flagging out-of-service equipment;
(7) Safety and environmental consequences of deviating from your equipment operating limits and steps required to correct or avoid this deviation;
(8) Properties of, and hazards presented by, the chemicals used in the operations;
(9) Precautions you will take to prevent the exposure of chemicals used in your operations to personnel and the environment. The precautions must include control technology, personal protective equipment, and measures to be taken if physical contact or airborne exposure occurs;
(10) Raw materials used in your operations and the quality control procedures you used in purchasing these raw materials;
(11) Control of hazardous chemical inventory; and
(12) Impacts to the human and marine environment identified through your hazards analysis.
(b) Operating procedures must be accessible to all employees involved in the operations.
(c) Operating procedures must be reviewed at the conclusion of specified periods and as often as necessary to assure they reflect current and actual operating practices, including any changes made to your operations.
(d) You must develop and implement safe and environmentally sound work practices for identified hazards during operations and the degree of hazard presented.
(e) Review of and changes to the procedures must be documented and communicated to responsible personnel.
Your SEMS program must establish and implement safe work practices designed to minimize the risks associated with operating, maintenance, and modification activities and the handling of materials and substances that could affect safety or the environment. Your SEMS program must also document contractor selection criteria. When selecting a contractor, you must obtain and evaluate information regarding the contractor's safety and environmental performance. Operators must ensure that contractors have their own written safe work practices. Contractors may adopt appropriate sections of the operator's SEMS program. Operator and contractor must document their agreement on appropriate contractor safety and environmental policies and practices before the contractor begins work at the operator's facilities.
(a) A contractor is anyone performing work for the lessee. However, these requirements do not apply to contractors providing domestic services to the lessee or other contractors. Domestic services include janitorial work, food and beverage service, laundry service, housekeeping, and similar activities.
(b) You must document that your contracted employees are knowledgeable and experienced in the work practices necessary to perform their job in a safe and environmentally sound manner. Documentation of each contracted employee's expertise to perform his/her
(c) Your SEMS program must include procedures and verification for selecting a contractor as follows:
(1) Your SEMS program must have procedures that verify that contractors are conducting their activities in accordance with your SEMS program.
(2) You are responsible for making certain that contractors have the skills and knowledge to perform their assigned duties and are conducting these activities in accordance with the requirements in your SEMS program.
(3) You must make the results of your verification for selecting contractors available to BOEMRE upon request.
(d) Your SEMS program must include procedures and verification that contractor personnel understand and can perform their assigned duties for activities such as, but not limited to:
(1) Installation, maintenance, or repair of equipment;
(2) construction, startup, and operation of your facilities;
(3) turnaround operations;
(4) major renovation; or
(5) specialty work.
(e) You must:
(1) Perform periodic evaluations of the performance of contract employees that verifies they are fulfilling their obligations, and
(2) maintain a contractor employee injury and illness log for 2 years related to the contractor's work in the operation area, and include this information on Form MMS-131.
(f) You must inform your contractors of any known hazards at the facility they are working on including, but not limited to fires, explosions, slips, trips, falls, other injuries, and hazards associated with lifting operations.
(g) You must develop and implement safe work practices to control the presence, entrance, and exit of contract employees in operation areas.
Your SEMS program must establish and implement a training program so that all personnel are trained to work safely and are aware of environmental considerations offshore, in accordance with their duties and responsibilities. Training must address the operating procedures (§ 250.1913), the safe work practices (§ 250.1914), and the emergency response and control measures (§ 250.1918). You must document the qualifications of your instructors. Your SEMS program must address:
(a) Initial training for the basic well-being of personnel and protection of the environment, and ensure that persons assigned to operate and maintain the facility possess the required knowledge and skills to carry out their duties and responsibilities, including startup and shutdown.
(b) Periodic training to maintain understanding of, and adherence to, the current operating procedures, using periodic drills, to verify adequate retention of the required knowledge and skills.
(c) Communication requirements to ensure that whenever a change is made to operating procedures (§ 250.1913), the safe work practices (§ 250.1914), or the emergency response and control measures (§ 250.1918), personnel will be trained in or otherwise informed of the change before they are expected to operate the facility.
(d) How you will verify that the contractors are trained in the work practices necessary to perform their jobs in a safe and environmentally sound manner, including training on operating procedures (§ 250.1913), the safe work practices (§ 250.1914), or the emergency response and control measures (§ 250.1918).
You must develop and implement written procedures that provide instructions to ensure the mechanical integrity and safe operation of equipment through inspection, testing, and quality assurance. The purpose of mechanical integrity is to ensure that equipment is fit for service. Your mechanical integrity program must encompass all equipment and systems used to prevent or mitigate uncontrolled releases of hydrocarbons, toxic substances, or other materials that
(a) The design, procurement, fabrication, installation, calibration, and maintenance of your equipment and systems in accordance with the manufacturer's design and material specifications.
(b) The training of each employee involved in maintaining your equipment and systems so that your employees can implement your mechanical integrity program.
(c) The frequency of inspections and tests of your equipment and systems. The frequency of inspections and tests must be in accordance with BOEMRE regulations and meet the manufacturer's recommendations. Inspections and tests can be performed more frequently if determined to be necessary by prior operating experience.
(d) The documentation of each inspection and test that has been performed on your equipment and systems. This documentation must identify the date of the inspection or test; include the name and position, and the signature of the person who performed the inspection or test; include the serial number or other identifier of the equipment on which the inspection or test was performed; include a description of the inspection or test performed; and the results of the inspection test.
(e) The correction of deficiencies associated with equipment and systems that are outside the manufacturer's recommended limits. Such corrections must be made before further use of the equipment and system.
(f) The installation of new equipment and constructing systems. The procedures must address the application for which they will be used.
(g) The modification of existing equipment and systems. The procedures must ensure that they are modified for the application for which they will be used.
(h) The verification that inspections and tests are being performed. The procedures must be appropriate to ensure that equipment and systems are installed consistent with design specifications and the manufacturer's instructions.
(i) The assurance that maintenance materials, spare parts, and equipment are suitable for the applications for which they will be used.
Your SEMS program must require that the commissioning process include a pre-startup safety and environmental review for new and significantly modified facilities that are subject to this subpart to confirm that the following criteria are met:
(a) Construction and equipment are in accordance with applicable specifications.
(b) Safety, environmental, operating, maintenance, and emergency procedures are in place and are adequate.
(c) Safety and environmental information is current.
(d) Hazards analysis recommendations have been implemented as appropriate.
(e) Training of operating personnel has been completed.
(f) Programs to address management of change and other elements of this subpart are in place.
(g) Safe work practices are in place.
Your SEMS program must require that emergency response and control plans are in place and are ready for immediate implementation. These plans must be validated by drills carried out in accordance with a schedule defined by the SEMS training program (§ 250.1915). The SEMS emergency response and control plans must include:
(a) Emergency Action Plan that assigns authority and responsibility to the appropriate qualified person(s) at a facility for initiating effective emergency response and control, addressing emergency reporting and response requirements, and complying with all applicable governmental regulations;
(b) Emergency Control Center(s) designated for each facility with access to the Emergency Action Plans, oil spill contingency plan, and other safety and environmental information (§ 250.1910); and
(c) Training and Drills incorporating emergency response and evacuation procedures conducted periodically for all personnel (including contractor's personnel), as required by the SEMS training program (§ 250.1915). Drills must be based on realistic scenarios conducted periodically to exercise elements contained in the facility or area emergency action plan. An analysis and critique of each drill must be conducted to identify and correct weaknesses.
To learn from incidents and help prevent similar incidents, your SEMS program must establish procedures for investigation of all incidents with serious safety or environmental consequences and require investigation of incidents that are determined by facility management or BOEMRE to have possessed the potential for serious safety or environmental consequences. Incident investigations must be initiated as promptly as possible, with due regard for the necessity of securing the incident scene and protecting people and the environment. Incident investigations must be conducted by personnel knowledgeable in the process involved, investigation techniques, and other specialties that are relevant or necessary.
(a) The investigation of an incident must address the following:
(1) The nature of the incident;
(2) The factors (human or other) that contributed to the initiation of the incident and its escalation/control; and
(3) Recommended changes identified as a result of the investigation.
(b) A corrective action program must be established based on the findings of the investigation in order to analyze incidents for common root causes. The corrective action program must:
(1) Retain the findings of investigations for use in the next hazard analysis update or audit;
(2) Determine and document the response to each finding to ensure that corrective actions are completed; and
(3) Implement a system whereby conclusions of investigations are distributed to similar facilities and appropriate personnel within their organization.
(a) You must have your SEMS program audited by either an independent third-party or your designated and qualified personnel according to the requirements of this subpart and API RP 75, Section 12 (incorporated by reference as specified in § 250.198) within 2 years of the initial implementation of the SEMS program and at least once every 3 years thereafter. The audit must be a comprehensive audit of all thirteen elements of your SEMS program to evaluate compliance with the requirements of this subpart and API RP 75 to identify areas in which safety and environmental performance needs to be improved.
(b) Your audit plan and procedures must meet or exceed all of the recommendations included in API RP 75 section 12 (incorporated by reference as specified in § 250.198) and include information on how you addressed those recommendations. You must specifically address the following items:
(1) Section 12.1 General.
(2) Section 12.2 Scope.
(3) Section 12.3 Audit Coverage.
(4) Section 12.4 Audit Plan. You must submit your written Audit Plan to BOEMRE at least 30 days before the audit. BOEMRE reserves the right to modify the list of facilities that you propose to audit.
(5) Section 12.5 Audit Frequency, except your audit interval must not exceed 3 years after the 2 year time period for the first audit.
(6) Section 12.6 Audit Team. The audit that you submit to BOEMRE must be conducted by either an independent third party or your designated and qualified personnel. The independent third party or your designated and qualified personnel must meet the requirements in § 250.1926.
(c) You must require your auditor (independent third party or your designated and qualified personnel) to submit an audit report of the findings and conclusions of the audit to BOEMRE within 30 days of the audit completion
(d) You must provide the BOEMRE a copy of your plan for addressing the deficiencies identified in your audit within 30 days of completion of the audit. Your plan must address the following:
(1) A proposed schedule to correct the deficiencies identified in the audit. BOEMRE will notify you within 14 days of receipt of your plan if your proposed schedule is not acceptable.
(2) The person responsible for correcting each identified deficiency, including their job title.
(e) BOEMRE may verify that you undertook the corrective actions and that these actions effectively address the audit findings.
(a) BOEMRE or its authorized representative may evaluate or visit your facility to determine whether your SEMS program is in place, addresses all required elements, and is effective in protecting the safety and health of workers, the environment, and preventing incidents. BOEMRE or its authorized representative may evaluate your SEMS program, including documentation of contractors, independent third parties, your designated and qualified personnel, and audit reports, to assess your SEMS program. These evaluations or visits may be random or based upon the OCS lease operator's or contractor's performance.
(b) For the evaluations, you must make the following available to BOEMRE upon request:
(1) Your SEMS program;
(2) The qualifications of your independent third-party or your designated and qualified personnel;
(3) The SEMS audits conducted of your program;
(4) Documents or information relevant to whether you have addressed and corrected the deficiencies of your audit; and
(5) Other relevant documents or information.
(c) During the site visit BOEMRE may verify that:
(1) Personnel are following your SEMS program,
(2) You can explain and demonstrate the procedures and policies included in your SEMS program; and
(3) You can produce evidence to support the implementation of your SEMS program.
(d) Representatives from BOEMRE may observe or participate in your SEMS audit. You must notify the BOEMRE at least 30-days prior to conducting your audit as required in § 250.1920, so that BOEMRE may make arrangements to observe or participate in the audit.
(a) If BOEMRE identifies safety or non-compliance concerns based on the results of our inspections and evaluations, or as a result of an event, BOEMRE may direct you to have an independent third-party audit of your SEMS program, in addition to the regular audit required by § 250.1920, or BOEMRE may conduct an audit.
(1) If BOEMRE direct you to have an independent third-party audit,
(i) You are responsible for all of the costs associated with the audit, and
(ii) The independent third-party audit must meet the requirements of § 250.1920 of this part and you must ensure that the independent third party submits the findings and conclusions of a BOEMRE-directed audit according to the requirements in § 250.1920 to BOEMRE within 30 days after the audit is completed.
(2) If BOEMRE conducts the audit, BOEMRE will provide a report of the findings and conclusions within 30 days of the audit.
(b) Findings from these audits may result in enforcement actions as identified in § 250.1927.
(c) You must provide the BOEMRE a copy of your plan for addressing the deficiencies identified in the BOEMRE-directed audit within 30 days of completion of the audit as required in § 250.1920.
(a) You must either choose an independent third-party or your designated and qualified personnel to audit your SEMS program. You must take into account the following qualifications when selecting the third-party or your designated and qualified personnel:
(1) Previous education and experience with SEMS, or similar management related programs.
(2) Technical capabilities of the individual or organization for the specific project.
(3) Ability to perform the independent third-party functions for the specific project considering current commitments.
(4) Previous experience with BOEMRE regulatory requirements and procedures.
(5) Previous education and experience to comprehend and evaluate how the company's offshore activities, raw materials, production methods and equipment, products, byproducts, and business management systems may impact health and safety performance in the workplace.
(b) You must have procedures to avoid conflicts of interest related to the development of your SEMS program and the independent third party auditor and your designated and qualified personnel.
(c) BOEMRE may evaluate the qualifications of the independent third parties or your designated and qualified personnel. This may include an audit of documents and procedures or interviews. BOEMRE may disallow audits by a specific independent third-party or your designated and qualified personnel if they do not meet the criteria of this section.
If BOEMRE determines that your SEMS program is not in compliance with this subpart we may initiate one or more of the following enforcement actions:
(a) Issue an Incident(s) of Noncompliance;
(b) Assess civil penalties; or
(c) Initiate probationary or disqualification procedures from serving as an OCS operator.
(a) Your SEMS program procedures must ensure that records and documents are maintained for a period of 6 years, except as provided below. You must document and keep all SEMS audits for 6 years and make them available to BOEMRE upon request. You must maintain a copy of all SEMS program documents at an onshore location.
(b) For JSAs, the person in charge of the activity must document the results of the JSA in writing and must ensure that records are kept onsite for 30 days. You must retain these records for 2 years and make them available to BOEMRE upon request.
(c) You must document and date all management of change provisions as specified in § 250.1912. You must retain these records for 2 years and make them available to BOEMRE upon request.
(d) You must keep your injury/illness log for 2 years and make them available to BOEMRE upon request.
(e) You must keep all evaluations completed on contractor's safety policies and procedures for 2 years and make them available to BOEMRE upon request.
(f) You must keep all records in an orderly manner, readily identifiable, retrievable and legible, and include the date of any and all revisions.
You must submit Form MMS-131 on an annual basis by March 31st. The form must be broken down quarterly, reporting the previous calendar year's data.
31 U.S.C. 9701, 43 U.S.C. 1334.
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
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
(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
(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, 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)
(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 sale, trade, license, or other agreement; and
(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) Permittees and third parties may apply to MMS for an extension of the 25-year proprietary term for geophysical information reprocessed 20 or more years after MMS issued the germane permit. You must submit the application to MMS within 90 days after completion of the reprocessing, except during the initial 1-year grace period as provided in paragraph (b)(5) below. Filing locations are listed in § 251.5(d). Your application must include:
(i) Name and address of the permittee or third party;
(ii) Product name;
(iii) Identification of the geophysical information area;
(iv) Identification of originating permit number and date;
(v) Description of reprocessing performed;
(vi) Identification of the date of completion of reprocessing the geophysical information;
(vii) Certification that the product meets the definition of processed geophysical information and that all other information in the application is accurate; and
(viii) Signature and date.
(3) With each new reprocessing of permitted data, you may apply for an extension of up to 5 years. However, the maximum proprietary term for geophysical information is 50 years after MMS issued the permit. Once the maximum term is reached, the MMS Regional Director will release the information to the public.
(4) Geophysical information processed or reprocessed 20 or more years after MMS issued the germane permit and granted the extension will be subject to submission, inspection, and selection criteria under 30 CFR 251.12 and reimbursement criteria identified under 30 CFR 251.13.
(5) There will be a 1-year grace period, starting September 14, 2009, to allow permittees and third parties sufficient time to meet the above requirements and to apply for all eligible extensions. During this time, MMS will not release geophysical information which was reprocessed 20 or more years after the date that MMS issued the germane permit.
(6) After September 14, 2010 MMS will resume releasing eligible reprocessed information. If an application for extension is not filed, not filed on time, or not approved by MMS, the original 25-year proprietary term applies to the release date of the reprocessed geophysical information.
(7) 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.
(8) MMS may allow limited inspection, but only by persons with a direct interest in related MMS decisions and issues in specific geographic areas, and who agree in writing to its confidentiality, of G&G data and information submitted under this part that MMS uses to:
(i) Make unitization determinations on two or more leases;
(ii) Make competitive reservoir determinations;
(iii) Ensure proper plans of development for competitive reservoirs;
(iv) Promote operational safety;
(v) Protect the environment;
(vi) Make field determinations; or
(vii) Determine eligibility for royalty relief.
(c)
(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 5438, 1849 C Street, NW., Washington, DC 20240.
OCS Lands Act, 43 U.S.C. 1331
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 transshipment which 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 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
(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 to comment on the intended action. When the Director so notifies a lessee or permittee of the intent to disclose data or information to an independent contractor or agent, all other owners of such data or information shall be deemed to have been notified of the Director's intent. Prior to any such disclosure, the contractor or agent shall be required to execute a written commitment not to disclose any data or information to anyone without the express consent of the Director, and not to make any disclosure or use of the data or information other than that provided in the contract. Contracts between the Minerals Management Service and independent contractors shall be available to the lessee(s) or permittee(s) for inspection. In the event of any unauthorized use or disclosure of data or information by the contractor or agent, or by an employee thereof, the responsible contractor or agent or employee thereof shall be liable for penalties pursuant to section 24 of the Act.
(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
(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
(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. 2716, 28 U.S.C. 2461.
At 76 FR 38296, June 30, 2011, the authority citation for part 253 was revised, effective Aug. 1, 2011. For the convenience of the user, the revised text is set forth as follows:
28 U.S.C. 2461 note, 33 U.S.C. 2716.
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 names, addresses, and telephone numbers of responsible parties for covered facilities and their designated agents, guarantors, and U.S. agents for service of process for claims associated with oil pollution from designated covered facilities. The requirement to provide the information is mandatory. No information submitted for OSFRC is confidential or proprietary.
(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 5438, 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
(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
(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 (
(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 times the self-insurance amount requested for demonstration.
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 (
(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) (
(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 of the participating insurers. MMS will accept your fax binder as OSFR evidence during a period that ends 90 days after the date that you need the insurance to demonstrate OSFR.
(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
(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 instrument issuer for claims arising from an incident (
(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 (
(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
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 $27,500 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.
At 76 FR 38296, June 30, 2011, § 253.51 was amended by revising paragraph (a), effective Aug. 1, 2011. For the convenience of the user, the revised text is set forth as follows:
(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 $30,000 per COF per day of violation (that is, each day a COF is operated without acceptable evidence of OSFR).
(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 (
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
(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 leases or facilities. All the leases or facilities in your plan must have the same owner or operator (including affiliates) and must be located in the same MMS Region (see definition of Regional Response Plan in § 254.6).
(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
(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 5438, 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
(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 address, and telephone number (including facsimile number if applicable):
(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
(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 analysis. You also must state the strategies that you will use for their protection. At a minimum, this list must include those resources of special economic and environmental importance, if any, specified in the appropriate Area Contingency Plan(s).
(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
(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 Plan(s). Your in situ burning plan must include:
(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 of 1 barrel or more. The Regional Supervisor must receive this confirmation within 15 days after the spillage has been stopped. All reports must include the cause, location, volume, and remedial action taken. Reports of spills of more than 50 barrels must include information on the sea state, meteorological conditions, and the size and appearance of the slick. The Regional Supervisor may require additional information if it is determined that an analysis of the response is necessary.
(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
31 U.S.C. 9701, 42 U.S.C. 6213, 43 U.S.C. 1334, Pub. L. 109-432.
(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 qualified to hold such a lease. Response is required to obtain a benefit according to 43 U.S.C. 1331
(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 5438, 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)
(m)
(1) A bonus due for a lease on the Outer Continental Shelf; or
(2) A royalty due on oil or gas production from any lease located on the Outer Continental Shelf.
(n)
(o)
(p)
(q)
(r)
(s)
(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 in paragraph (b) of this section, is subject to lease for any mineral not included in a subsisting lease issued under the act or meeting the requirements of subsection (a) of section 6 of the Act. Before any lease is offered or issued an area may be (1) withdrawn from disposition pursuant to section 12(a) of the Act, or (2) designated as an area or part of an area restricted from operation under section 12(d) of the Act.
(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
(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.
(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 days prior to publication of the proposed program in the
(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 request other interested Federal Agencies to prepare reports describing, to the extent known, any other valuable resources contained within the general area and the potential effect of mineral operations upon the resources or upon the total environment or other uses of the area.
(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 this part, the Director's recommendation shall be replaced by a statement describing the results of the Director's consideration of the factors specified above in this section.
(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
(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 apply to §§ 256.38 through 256.44 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 (
(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, that lands being offered have extremely high cost exploration and development problems and that exploration and development will not occur on such lands unless the exemption is granted.
(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
(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 with the Secretary, with a copy to the authorized officer, a written request for reconsideration accompanied by a statement of reasons. The Secretary shall respond in writing either affirming or reversing the decision of the authorized officer.
(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 Gulf of Mexico and the area offshore the 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 alternative form of security maintained under this section, the surety's remaining liability under the bond or alternative 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 alternative 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 alternative types of security instruments instead of providing a bond if the Regional Director determines that the alternative security protects the interests of the United States to the same extent as the required bond.
(1) If you pledge an alternative 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 alternative 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
(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 (
(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 256.53 of this part to the Regional Director and advise the Regional Director of the lapse in your previous bond.
(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 § 250.1703 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
(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 MMS will terminate the period of liability of a bond or cancel a bond. Terminating the period of liability of a bond ends the period during which obligations continue to accrue but does not relieve the surety of the responsibility for obligations that accrued during the period of liability. Canceling a bond relieves the surety of all liability. The liabilities that accrue during a period of liability include obligations that started to accrue prior to the beginning of the period of liability and had not been met and obligations that begin accruing during the period of liability.
(a) When the surety under your bond requests termination:
(1) The Regional Director will terminate the period of liability under your bond within 90 days after MMS receives the request; and
(2) If you intend to continue operations, or have not met all end of lease obligations, you must provide a replacement bond of an equivalent amount.
(b) If you provide a replacement bond, the Regional Director will cancel your previous bond and the surety that provided your previous bond will not retain any liability, provided that:
(1) The new bond is equal to or greater than the bond that was terminated, or you provide an alternative form of security, and the Regional Director determines that the alternative form of security provides a level of security equal to or greater than that provided for by the bond that was terminated;
(2) For a base bond submitted under § 256.52(a) or under § 256.53(a) or (b), the surety issuing the new bond agrees to assume all outstanding liabilities that accrued during the period of liability that was terminated; and
(3) For supplemental bonds submitted under § 256.53(d), the surety issuing the new supplemental bond agrees to assume that portion of the outstanding liabilities that accrued during the period of liability which was terminated and that the Regional Director determines may exceed the coverage of the base bond, and of which the Regional Director notifies the provider of the bond.
(c) This paragraph applies if the period of liability is terminated for a bond but the bond is not replaced by a bond of an equivalent amount. The surety that provided your terminated bond will continue to be responsible for accrued obligations:
(1) Until the obligations are satisfied; and
(2) For additional periods of time in accordance with paragraph (d) of this section.
(d) When your lease expires or is terminated, the surety that issued a bond will continue to be responsible, and the Regional Director will retain other forms of security as shown in the following table:
(e) For all bonds, the Regional Director may reinstate your bond 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 was materially false when the bond was 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 Q.
(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.
(a) The table in this paragraph (a) shows the fees that you must pay to MMS for the services listed. The fees will be adjusted periodically according to the Implicit Price Deflator for Gross Domestic Product by publication of a document in the
(b) Once a fee is paid, it is nonrefundable, even if an application or other request is withdrawn. If your application is returned to you as incomplete, you are not required to submit a new fee with the amended application.
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, you must file instruments creating or transferring carried working interests, overriding royalty interests, or payments out of production with the Regional Director for record purposes.
(8) You must pay electronically through
(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 agreements applicable to the acquisition of that lease or a fractional interest.
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
(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 production in paying quantities for all purposes of the lease.
(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,
(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 sulfur, subject to section 6(b)(2) of the Act) shall continue in effect, and, in the event of any conflict or inconsistency, shall take precedence over these regulations.
(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.
You may exchange a lease for a bonus or royalty credit if it:
(a) Was in effect on December 20, 2006, and
(b) Is located in:
(1) The Eastern planning area and within 125 miles of the coastline of the State of Florida, or
(2) The Central planning area and within the Desoto Canyon OPD, the Destin Dome OPD, or the Pensacola OPD, and within 100 miles of the coastline of the State of Florida.
The amount of the bonus or royalty credit for an exchanged lease equals the sum of:
(a) The amount of the bonus payment; and
(b) All rent paid for the lease as of the date the lessee submits the request to exchange the lease under § 256.92 to MMS.
(a) To obtain the bonus or royalty credit, all of the record title interest owners in the lease must submit the following to the MMS Regional Supervisor for Leasing and Environment for
(1) A written request to exchange the lease for the bonus or royalty credit, signed by all record title interest owners in the lease.
(2) The name and contact information for a person who will act as a contact for each record title interest owner.
(3) Documentation of each record title interest owner's percentage share in the lease.
(4) A list of all bonus and rental payments for that lease made by, or on behalf of, each of the current record title owners.
(5) A written relinquishment of the lease as described in § 256.76. Notwithstanding § 256.76, the relinquishment will become effective when the credit becomes effective under paragraph (b) of this section.
(b) The credit becomes effective when MMS issues a certification to the record title interest owners that the lease has qualified for the credit.
The MMS will allocate the bonus or royalty credit for an exchanged lease to the current record title interest owners in the same percentage share as each owner has in the lease as of the date of the request to exchange the lease.
(a) You may use a credit issued under this part in lieu of a monetary payment due under any lease in the Gulf of Mexico not subject to the revenue distribution provisions of section 8(g)(2) of the OCSLA (43 U.S.C. 1337(g)(2)) for either:
(1) A bonus for acquisition of an interest in a new lease; or
(2) Royalty due on oil and gas production after October 14, 2008.
(b) You may not use a bonus or royalty credit in lieu of delivering oil or gas taken as royalty-in-kind.
(c) If you have any credit that remains unused after 5 years from the date MMS issued the credit, MMS reserves the right to apply the remaining credit to any of your obligations.
(a) You may transfer your bonus or royalty credit to any other person by submitting to the MMS Adjudication Unit for the Gulf of Mexico two originally executed transfer letters of agreement.
(b) Authorized officers indicated on the qualification card filed with MMS of all companies involved in transferring and receiving the credit must sign the transfer letters of agreement.
(c) A transfer letter of agreement must include:
(1) The effective date of the transfer,
(2) The OCS-G number for the lease that originally qualified for the credit,
(3) The amount of the credit being transferred,
(4) Company names punctuated exactly as filed on the qualification card at MMS, and
(5) A corporate seal, if you used a corporate seal in your initial qualification to hold OCS leases.
(d) The transferee of a credit transferred under this section may use it in accordance with § 256.94 as soon as MMS sends a confirmation of the transfer to the transferee.
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
Part 260 implements the Outer Continental Shelf Lands Act (OCSLA), 43 U.S.C. 1331
(a) Implementing alternative bidding systems;
(b) Prohibiting joint bidding for development rights by certain types of joint ventures; and
(c) Establishing diligence requirements for Federal OCS leases.
(a) The Paperwork Reduction Act of 1995 (PRA) 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. The information collection under 30 CFR part 260 is either exempt from the PRA (5 CFR 1320.4(a)(2), (c)) or refers to requirements covered under 30 CFR parts 203 and 256.
(b) You may send comments regarding any aspect of the collection of information under this part to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 20240.
This subpart establishes the bidding systems that we may use to offer and sell Federal leases for the exploration, development, and production of oil and gas resources located on the OCS.
(1) Is issued as part of an OCS lease sale held after November 28, 1995, and before November 28, 2000;
(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper;
(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and
(4) Is offered subject to a royalty suspension volume.
(1) Is issued as part of an OCS lease sale held before November 28, 1995;
(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper; and
(3) Lies wholly west of 87 degrees, 30 minutes West longitude. (See part 203 of this title.)
(1) Is issued as part of an OCS lease sale held after November 28, 2000;
(2) Is in locations or planning areas specified in a particular Notice of OCS Lease Sale; and
(3) Is offered subject to a royalty suspension specified in a Notice of OCS Lease Sale published in the
We will apply a single bidding system selected from those listed in this section to each tract included in an OCS lease sale. The following table lists bidding systems, the bid variables, and characteristics.
(a) For each of the bidding systems in § 260.110, we will include an annual rental fee. Other fees and provisions may apply as well. The Notice of OCS Lease Sale published in the
(b) If we use any deferment or schedule of payments for the cash bonus bid, we will specify and include it in the Notice of OCS Lease Sale published in the
(c) For the bidding systems listed in this subpart, if the bid variable is a cash bonus bid, the highest bid by a qualified bidder determines the amount of cash bonus to be paid. We will include the minimum bid level(s) in the Notice of OCS Lease Sale published in the
(d) For the bidding systems listed in this subpart, if the bid variable is the royalty rate, the highest bid by a qualified bidder determines the royalty rate to be paid. We will include the minimum royalty rate(s) in the Notice of OCS Lease Sale published in the
(e) We may, by rule, add to or modify the bidding systems listed in § 260.110, according to the procedural requirements of the OCSLA, 43 U.S.C. 1331
Royalty suspension volumes, as specified in section 304 of the Act, apply to eligible leases that meet the criteria in § 260.113. For purposes of this section and §§ 260.113 through 260.117:
(a) Any volumes of production that are not normally royalty-bearing under the lease or the regulations (e.g., fuel gas) do not count against royalty suspension volumes; and
(b) Production includes volumes allocated to a lease under an approved unit agreement.
(a) Your eligible lease will receive a royalty suspension volume as specified in the Act. The bidding system in § 260.110(g) applies.
(b) Your eligible lease may receive a royalty suspension volume only if your entire lease is west of 87 degrees, 30 minutes West longitude.
(a) We have specified the water depth category for each eligible lease in the final Notice of OCS Lease Sale Package. The Final Notice of Sale is published in the
(b) We have specified in the Notice of OCS Lease Sale the royalty suspension volume applicable to each water depth. The following table shows the royalty suspension volumes for each eligible lease in million barrels of oil equivalent (MMBOE):
A royalty suspension volume for an eligible lease will continue through the end of the month in which cumulative production from the leases in a field entitled to share the royalty suspension volume reaches that volume or the lease period ends.
You must measure natural gas production on your eligible lease subject to the royalty suspension volume as follows: 5.62 thousand cubic feet of natural gas, measured according to part 250, subpart L of this title, equals one barrel of oil equivalent.
We may issue leases with suspension of royalties for a period, volume or value of production, as authorized in section 303 of the Act. For purposes of this section and §§ 260.121 through 260.124:
(a) Any volumes of production that are not normally royalty-bearing under the lease or the regulations (e.g., fuel
(b) Production includes volumes allocated to a lease under an approved unit agreement.
(a) We will specify any royalty suspension for your RS lease in the Notice of OCS Lease Sale published in the
(1) Your RS lease may produce royalty-free the royalty suspension we specify for your lease, even if the field to which we assign it is producing.
(2) The royalty suspension we specify in the Notice of OCS Lease Sale for your lease does not apply to any other leases in the field to which we assign your RS lease.
(b) You may apply for a supplemental royalty suspension for a project under part 203 of this title, if your lease is located:
(1) In the Gulf of Mexico, in water 200 meters or deeper, and wholly west of 87 degrees, 30 minutes West longitude; or
(2) Offshore of Alaska.
(c) Your RS lease retains the royalty suspension with which we issued it even if we deny your application for more relief.
(a) The royalty suspension volume for your RS lease will continue through the end of the month in which cumulative production from your lease reaches the applicable royalty suspension volume or the lease period ends.
(b)(1) Notwithstanding any royalty suspension volume under this subpart, you must pay royalty at the lease stipulated rate on:
(i) Any oil produced for any period stipulated in the lease during which the arithmetic average of the daily closing price on the New York Mercantile Exchange (NYMEX) for light sweet crude oil exceeds the applicable threshold price of $36.39 per barrel, adjusted annually after calendar year 2007 for inflation unless the lease terms prescribe a different price threshold.
(ii) Any natural gas produced for any period stipulated in the lease during which the arithmetic average of the daily closing price on the NYMEX for natural gas exceeds the applicable threshold price of $4.55 per MMBtu, adjusted annually after calendar year 2007 for inflation unless the lease terms prescribe a different price threshold.
(iii) Determine the threshold price for any calendar year after 2007 by adjusting the threshold price in the previous year by the percentage that the implicit price deflator for the gross domestic product, as published by the Department of Commerce, changed during the calendar year.
(2) You must pay any royalty due under this paragraph, plus late payment interest under § 218.54 of this title, no later than 90 days after the end of the period for which royalty is owed.
(3) Any production on which you must pay royalty under this paragraph will count toward the production volume determined under §§ 260.120 through 260.124.
(c) If you must pay royalty on any product (either oil or natural gas) for any period under paragraph (b), you must continue to pay royalty on that product during the next succeeding period of the same length until the arithmetic average of the daily closing NYMEX prices for that product for that period can be determined. If the arithmetic average of the daily closing prices for that product for that period is less than the threshold price stipulated in the lease, you are entitled to a credit or refund of royalties paid for that period with interest under applicable law.
You must measure natural gas production subject to the royalty suspension volume for your lease as follows: 5.62 thousand cubic feet of natural gas,
(a) We will assign your lease that has a qualifying well (under part 250, subpart A of this title) to an existing field or designate a new field and will notify you and other affected lessees and operating rights holders in the field of that assignment.
(1) Within 15 days of the final notification, you or any of the other affected lessees or operating rights holders may file a written request with the Director for reconsideration, accompanied by a Statement of Reasons.
(2) The Director will respond in writing either affirming or reversing the assignment decision. The Director's decision is the final action of the Department of the Interior and is not subject to appeal to the Interior Board of Land Appeals under part 290 of this title and 43 CFR part 4.
(b) If we establish a royalty suspension volume for a field as a result of an approved application for royalty relief submitted for a pre-Act lease under part 203 of this chapter, then:
(1) Royalty-free production from your RS lease shares from and counts as part of any royalty suspension volume under § 260.114(d) for the field to which we assign your lease; and
(2) Your RS lease may continue to produce royalty-free up to the royalty suspension we specified for your lease, even if the field to which we assign your RS lease has produced all of its royalty suspension volume.
(c) Your lease may share in a suspension volume larger than the royalty suspension with which we issued it and to the extent we grant a larger volume in response to an application by a pre-Act lease submitted under part 203 of this title. To share in any larger royalty suspension volume, you must file an application described in §§ 203.71 and 203.83. In no case will royalty-free production for your RS lease be less than the royalty suspension specified for your lease.
In analyzing the application of one of the bidding systems listed in § 260.110 to tracts selected for any OCS lease sale, we may, at our discretion, consider the following purposes and policies. We recognize that each of the purposes and policies may not be specifically applicable to the selection process for a particular bidding system or tract, or may present a conflict that we will have to resolve in the process of bidding system selection. The order of listing does not denote a ranking.
(a) Providing fair return to the Federal Government;
(b) Increasing competition;
(c) Ensuring competent and safe operations;
(d) Avoiding undue speculation;
(e) Avoiding unnecessary delays in exploration, development, and production;
(f) Discovering and recovering oil and gas;
(g) Developing new oil and gas resources in an efficient and timely manner;
(h) Limiting the administrative burdens on Government and industry; and
(i) Providing an opportunity to experiment with various bidding systems to enable us to identify those most appropriate for the satisfaction of the objectives of the United States in OCS lease sales.
The purpose of this subpart 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 the purposes of this subpart, all terms used are defined as in § 256.40 of this title.
(a) You must file a Statement of Production with the Director, according to the requirements of §§ 256.38 through 256.44 of this title if:
(1) You submit a joint bid for any OCS oil and gas lease during a 6-month bidding period; and
(2) You were chargeable for the prior production period with an average daily production from all sources in excess of 1.6 million barrels of crude oil, natural gas equivalents, and liquefied petroleum products.
(b) The Statement of Production that you file under paragraph (a) of this section must state that you are chargeable for the prior production period with an average daily production in excess of the quantities listed in paragraph (a) of this section.
(c) If your average daily production in the prior production period met or exceeded the quantities specified in paragraph (a) of this section, you may not submit a joint bid for any OCS oil and gas lease during the applicable 6-month bidding period with any other person similarly chargeable. We will disqualify and reject these bids.
(d) If your average daily production in the prior production period met or exceeded the quantities specified in paragraph (a) of this section, you may not enter into an agreement prior to a lease sale that would result in two or more persons, similarly chargeable, acquiring or holding any interest in the tract for which the bid is submitted. We will disqualify and reject these bids.
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 must proceed in accordance with the provisions of 30 CFR 250, subpart N.
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.
31 U.S.C. 9701, 43 U.S.C. 1334.
Definitions in this part have the following meaning:
(l) That is used, or is scheduled to be used, as a support base for geological and geophysical (G&G) prospecting or scientific research activities; or
(2) In which there is a reasonable probability of significant effect on land or water uses from such activity.
(1) Geological and geophysical marine and airborne surveys where magnetic, gravity, seismic reflection, seismic refraction, or the gathering through coring or other geological samples are used to detect or imply the presence of hard minerals; and
(2) Any drilling, whether on or off a geological structure.
(1) An agreement issued under section 8 or maintained under section 6 of the Act that authorizes mineral exploration, development and production; or
(2) The area covered by an agreement specified in paragraph (1) of this definition.
(1) Related to hard minerals on the OCS; and
(2) Not covered under a permit.
(1) That lie seaward and outside of the area of lands beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301); and
(2) Whose subsoil and seabed belong to the United States and are subject to its jurisdiction and control.
(1) Geological prospecting for hard minerals;
(2) Geophysical prospecting for hard minerals;
(3) Geological scientific research; or
(4) Geophysical scientific research.
(1) A citizen or national of the United States;
(2) An alien lawfully admitted for permanent residence in the United States as defined in section 8 U.S.C. 1101(a)(20);
(3) A private, public, or municipal corporation organized under the laws of the United States or of any State or territory thereof, and association of such citizens, nationals, resident aliens or private, public, or municipal corporations, States, or political subdivisions of States; or
(4) Anyone operating in a manner provided for by treaty or other applicable international agreements. The term does not include Federal agencies.
(1) Processing involves changing the form of data as to facilitate interpretation. Some examples of processing operations may include, but are not limited to:
(i) Applying corrections for known perturbing causes;
(ii) Rearranging or filtering data; and
(iii) Combining or transforming data elements.
(2) Reprocessing is the additional processing other than ordinary processing used in the general course of evaluation. Reprocessing operations may include varying identified parameters for the detailed study of a specific problem area.
The purpose of this part is to:
(a) Allow you to conduct prospecting activities or scientific research activities on the OCS in Federal waters related to hard minerals on unleased lands or on lands under lease to a third party.
(b) Ensure that you carry out prospecting activities or scientific research activities in a safe and environmentally sound manner so as to prevent harm or damage to, or waste of, any natural resources (including any hard minerals in areas leased or not leased), any life (including fish and other aquatic life), property, or the marine, coastal, or human environment.
(c) Inform you and third parties of your legal and contractual obligations.
(d) Inform you and third parties of:
(1) The U.S. Government's rights to access G&G data and information collected under permit on the OCS;
(2) Reimbursement we will make for data and information that are submitted; and
(3) The proprietary terms of data and information that we retain.
You must conduct G&G prospecting activities or scientific research activities under this part according to:
(a) The Act;
(b) The regulations in this part;
(c) Orders of the Director/Regional Director (RD); and
(d) Other applicable statutes, regulations, and amendments.
This part does not apply to:
(a) G&G prospecting activities conducted by, or on behalf of, the lessee on a lease on the OCS;
(b) Federal agencies;
(c) Postlease activities for mineral resources other than oil, gas, and sulphur, which are covered by regulations at 30 CFR part 282; and
(d) G&G exploration or G&G scientific research activities related to oil, gas, and sulphur, including gas hydrates, which are covered by regulations at 30 CFR part 251.
You must have an MMS-approved permit to conduct G&G prospecting activities, including deep stratigraphic tests, for hard minerals. If you conduct both G&G prospecting activities, you must have a separate permit for each.
You may conduct G&G scientific research activities related to hard minerals on the OCS only after you obtain an MMS-approved permit or file a notice.
(a)
(1) Using solid or liquid explosives;
(2) Drilling a deep stratigraphic test; or
(3) Developing data and information for proprietary use or sale.
(b)
(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) A map, plat, or chart, that shows the location where you will conduct research;
(5) The proposed projected starting and ending dates for your research activity;
(6) The name, registry number, registered owner, and port of registry of vessels used in the operation;
(7) The earliest practical 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 collect available to the public;
(9) A statement that you and others involved will not sell or withhold the data and information resulting from your research; and
(10) At your option, the nonexclusive use agreement for scientific research attachment to form MMS-134. (If you submit this agreement, you do not have to submit the material required in paragraphs (c)(7), (c)(8), and (c)(9) of this section.)
You must apply for a permit or file a notice at one of the following locations:
While conducting G&G prospecting or scientific research activities under a permit or notice, you must not:
(a) Interfere with or endanger operations under any lease, right-of-way, easement, right-of-use, notice, or permit issued or maintained under the Act;
(b) Cause harm or damage to life (including fish and other aquatic life), property, or the marine, coastal, or human environment;
(c) Cause harm or damage to any mineral resources (in areas leased or not leased);
(d) Cause pollution;
(e) Disturb archaeological resources;
(f) Create hazardous or unsafe conditions;
(g) Unreasonably interfere with or cause harm to other uses of the area; or
(h) Claim any oil, gas, sulphur, or other minerals you discover while conducting operations under a permit or notice.
While conducting G&G prospecting or scientific research activities under a permit or notice, you must:
(a) Immediately report to the RD if you:
(1) Detect hydrocarbon or any other mineral occurrences;
(2) Detect environmental hazards that imminently threaten life and property; or
(3) Adversely affect the environment, aquatic life, archaeological resources, or other uses of the area where you are prospecting or conducting scientific research activities.
(b) Consult and coordinate your G&G activities with other users of the area for navigation and safety purposes.
(c) If you conduct shallow test drilling or deep stratigraphic test drilling activities, you must use the best available and safest technologies that the RD considers economically feasible.
Before you begin modified operations, you must submit a written request describing the modifications and receive the RD's oral or written approval. If circumstances preclude a written request, you must make an oral request and follow up in writing.
(a) You must allow our representatives to inspect your G&G prospecting or any scientific research activities that are being conducted under a permit. They will determine whether operations are adversely affecting the environment, aquatic life, archaeological resources, or other uses of the area.
(b) MMS will reimburse you for food, quarters, and transportation that you provide for our representatives if you send in your reimbursement request to the region that issued the permit within 90 days of the inspection.
(a) You must submit status reports on a schedule specified in the permit and include a daily log of operations.
(b) You must submit a final report of G&G prospecting or scientific research activities under a permit within 30 days after you complete acquisition activities under the permit. You may combine the final report with the last status report and must include each of the following:
(1) A description of the work performed.
(2) Charts, maps, plats and digital navigation data in a format specified by the RD, showing the areas and blocks in which any G&G prospecting 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.
(3) The dates on which you conducted the actual prospecting or scientific research activities.
(4) A summary of any:
(i) Hard mineral, hydrocarbon, or sulphur occurrences encountered;
(ii) Environmental hazards; and
(iii) Adverse effects of the G&G prospecting or scientific research activities on the environment, aquatic life, archaeological resources, or other uses of the area in which the activities were conducted.
(5) Other descriptions of the activities conducted as specified by the RD.
(a) We may temporarily stop prospecting or scientific research activities under a permit when the RD 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, and any minerals (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 our 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) The RD will advise you either orally or in writing of the procedures to temporarily stop activities. We will confirm an oral notification in writing and deliver all written notifications by courier or certified/registered mail. You must stop all activities under a permit as soon as you receive an oral or written notification.
The RD will advise you when you may start your permit activities again.
The RD may cancel a permit at any time.
(a) If we cancel your permit, the RD will advise you by certified or registered mail 30 days before the cancellation date and will state the reason.
(b) After we cancel your permit, you are still responsible for proper abandonment of any drill site according to the requirements of 30 CFR 251.7(b)(8). You must comply with all other obligations specified in this part or in the permit.
(a) You may relinquish your permit at any time by advising the RD by certified or registered mail 30 days in advance.
(b) After you relinquish your permit, you are still responsible for proper abandonment of any drill sites according to the requirements of 30 CFR 251.7(b)(8). You must also comply with all other obligations specified in this part or in the permit.
We will evaluate the potential of proposed prospecting or scientific research activities for adverse impact on the environment to determine the need for mitigation measures.
We anticipate that activities of the type listed below typically will not cause significant environmental impact and 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) Hard minerals sampling of a limited nature such as shallow test drilling;
(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 hard mineral assaying and analysis; and
(j) Placement of positioning systems, including bottom transponders and surface and subsurface buoys reported in Notices to Mariners.
(a) In cases where Coastal Zone Management Act consistency review is required, the Director will notify the Governor of each adjacent State with a copy of the application for a permit immediately upon the submission for approval.
(b) In cases where an environmental assessment is to be prepared, the Director will invite the Governor of each adjacent State to review and provide comments regarding the proposed activities. The Director's invitation to provide comments will allow the Governor a specified period of time to comment.
(c) When a permit is issued, the Director will notify affected parties including each affected coastal State, Federal agency, local government, and special interest organization that has expressed an interest.
(a)
(1) Any provision of the Act;
(2) Any provisions of a G&G or drilling permit; or
(3) Any regulation or order issued under the Act.
(b)
(a) You must notify the RD, in writing, when you complete the initial analysis, processing, or interpretation of any geological data and information. Initial analysis and processing are the stages of analysis or processing where the data and information first become available for in-house interpretation by the permittee or become available commercially to third parties via sale, trade, license agreement, or other means.
(b) The RD may ask if you have further analyzed, processed, or interpreted any geological data and information. When asked, you must respond to us in writing within 30 days.
(c) The RD may ask you or a third party to submit the analyzed, processed, or interpreted geologic data and information for us to inspect or permanently retain. You must submit the data and information within 30 days after such a request.
Unless the RD specifies otherwise, you must submit geological data and information that include:
(a) An accurate and complete record of all geological (including geochemical) data and information describing each operation of analysis, processing, and interpretation;
(b) Paleontological reports identifying by depth any microscopic fossils
(c) Copies of well logs or charts in a digital format, if available;
(d) Results and data obtained from formation fluid tests;
(e) Analyses of core or bottom samples and/or a representative cut or split of the core or bottom sample;
(f) Detailed descriptions of any hydrocarbons or other minerals or hazardous conditions encountered during operations, including near losses of well control, abnormal geopressures, and losses of circulation; and
(g) Other geological data and information that the RD may specify.
A third party may obtain geological data and information from a permittee, or from another third party, by sale, trade, license agreement, or other means. If this happens:
(a) The third-party recipient of the data and information assumes the obligations under this part, except for the notification provisions of § 280.40(a) and is subject to the penalty provisions of § 280.32(a)(1) and 30 CFR part 250, subpart N; and
(b) 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
(c) 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 RD in writing within 30 days of the sale, trade, or other agreement, including the identity of the recipient of the data and information; or
(d) 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 RD, advise the RD, in writing, of the license agreement, including the identity of the recipient of the data and information.
(a) You must notify the RD in writing when you complete the initial processing and interpretation of any geophysical data and information. Initial processing is the stage of processing where the data and information become available for in-house interpretation by the permittee, or become available commercially to third parties via sale, trade, license agreement, or other means.
(b) The RD may ask whether you have further processed or interpreted any geophysical data and information. When asked, you must respond to us in writing within 30 days.
(c) The RD may request that the permittee or third party submit geophysical data and information before making a final selection for retention. Our representatives may inspect and select the data and information on your premises, or the RD can request delivery of the data and information to the appropriate regional office for review.
(d) You must submit the geophysical data and information within 30 days of receiving the request, unless the RD extends the delivery time.
(e) At any time before final selection, the RD may review and return any or all geophysical data and information. We will notify you in writing of any data the RD decides to retain.
Unless the RD specifies otherwise, you must include:
(a) An accurate and complete record of each geophysical survey conducted under the permit, including digital navigational data and final location maps;
(b) All seismic data collected under a permit presented in a format and of a quality suitable for processing;
(c) 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
(d) 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.
A third party may obtain geophysical data, processed geophysical information, or interpreted geophysical information from a permittee, or from another third party, by sale, trade, license agreement, or other means. If this happens:
(a) The third-party recipient of the data and information assumes the obligations under this part, except for the notification provisions of § 280.50(a) and is subject to the penalty provisions of § 280.32(a)(1) and 30 CFR 250, subpart N; and
(b) 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
(c) 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 RD, in writing within 30 days of the sale, trade, or other agreements, including the identity of the recipient of the data and information; or
(d) 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 RD, advise the RD, in writing, of the license agreement, including the identity of the recipient of the data and information.
(a) We will reimburse you or a third party for reasonable costs of reproducing data and information that the RD requests if:
(1) You deliver G&G data and information to us for the RD to inspect or select and retain (according to §§ 280.40 and 280.50);
(2) We receive your request for reimbursement and the RD 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) We will reimburse you or the third party for the reasonable costs of processing geophysical information (which does not include cost of data acquisition) if, at the request of the RD, you processed the geophysical data or information in a form or manner other than that used in the normal conduct of business.
(a) When you request reimbursement, you must identify reproduction and processing costs separately from acquisition costs.
(b) We 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.
In making data and information available to the public, the RD will follow the applicable requirements of:
(a) The Freedom of Information Act (5 U.S.C. 552);
(b) The implementing regulations at 43 CFR part 2;
(c) The Act; and
(d) The regulations at 30 CFR parts 250 and 252.
(1) If the RD determines that any data or information is exempt from
(i) You and all third parties agree to the disclosure; or
(ii) A provision of 30 CFR parts 250 and 252 allows us to make the disclosure.
(2) We will keep confidential the identity of third-party recipients of data and information collected under a permit. We will not release the identity unless you and the third parties agree to the disclosure.
(3) When you detect any significant hydrocarbon occurrences or environmental hazards on unleased lands during drilling operations, the RD will immediately issue a public announcement. The announcement must further the national interest without unduly damaging your competitive position.
We will release data and information that you or a third party submits and we retain according to paragraphs (a) and (b) of this section.
(a) If the data and information are not related to a deep stratigraphic test, we will release them to the public according to items (1), (2), and (3) in the following table:
(b) This paragraph applies if you are covered by paragraph (a)(4) of this section and a lease sale is held or a noncompetitive agreement is negotiated after you complete a test well. We will release the data and information related to the deep stratigraphic test at the earlier of the following times:
(1) Twenty-five years after you complete the test; or
(2) Sixty calendar days after we issue a lease, located partly or totally within 50 geographic miles (92.7 kilometers) of the test.
(a) When practical, the RD will advise the person who submitted data and information under §§ 280.40 or 280.50 of the intent to provide the data or information to an independent contractor or agent for reproduction, processing, and interpretation.
(b) The person notified will have at least five working days to comment on the action.
(c) When the RD advises the person who submitted the data and information, all other owners of the data or information will be considered to have been notified.
(d) The independent contractor or agent must sign a written commitment not to sell, trade, license, or disclose data or information to anyone without the RD's consent.
(a) We can disclose proprietary data, information, and samples submitted to us by permittees or third parties that we receive under this part to the Governor of any adjacent State that requests it according to paragraphs (b), (c), and (d) of this section. The permittee or third parties who submitted proprietary data, information, and samples will be notified about the disclosure and will have at least five working days to comment on the action.
(b) We will make a disclosure under this section only after the Governor and the Secretary have entered into an agreement containing all of the following provisions:
(1) The confidentiality of the information will be maintained.
(2) In any action taken for failure to protect the confidentiality of proprietary information, neither the Federal
(i) Any claim of sovereign immunity; or
(ii) Any claim that the employee who revealed the proprietary information was acting outside the scope of his/her employment in revealing the information.
(iii) The State agrees to hold the Federal Government 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.
(iv) The materials containing the proprietary data, information, and samples will remain the property of the Federal Government.
(c) The data, information, and samples available for reproduction to the State(s) under an agreement must be related to leased lands. Data and information on unleased lands may be viewed but not copied or reproduced.
(d) The State must return to us the materials containing the proprietary data, information, and samples when we ask for them or when the State no longer needs them.
(e) Information received and knowledge gained by a State official under paragraph (d) of this section is subject to confidentiality requirements of:
(1) The Act; and
(2) The regulations at 30 CFR parts 280, 281, and 282.
(a) The Office of Management and Budget (OMB) 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 prospecting does 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 prospecting permit.
(5) Inspect and select G&G data and information collected under an OCS prospecting 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 § 280.70 and 30 CFR part 281.
(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 5438, 1849 C Street, NW., Washington, DC 20240.
31 U.S.C. 9701, 43 U.S.C. 1334.
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. An applicant must respond to obtain or retain a benefit.
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 under 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 Production and Royalty Report (P & R) (MMS-4430) 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 forms and maintain auditable records in accordance with 30 CFR Chapter II, Subchapter A—Minerals Revenue Management.
(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 (
(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 that it is in the national interest, it will result in the conservation of natural resources of the OCS, it will promote development, or the mine cannot be successfully operated under existing conditions.
(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
(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
(2) An application for approval of any instrument required to be filed will not be accepted unless a nonrefundable fee of $50 is paid electronically through
(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 earning the continuation of the lease in effect.
(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
(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
(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 1334.
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 regulations. The requirement to respond is mandatory.
(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
(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 wishes to comment on a proposed Delineation Plan may do so within 30 days of the receipt of the proposed plan and the accompanying information.
(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
(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 direct interest in the affected lease(s), unitization agreement, or joint Mining Plan.
(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
(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
(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);
(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
(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 between alternative mitigation measures, the Director shall balance the cost of the required measures against the reduction or potential reduction in damage or threat of damage or harm to life (including fish and other aquatic life), to property, to any mineral deposits (in areas leased or not leased), to the national security or defense, or to the marine, coastal, or human environment.
(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
(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 or by certified or registered mail addressed to the lessee at the last known address.
(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
(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, taking account of 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 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),
(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 shall submit to the Director the designation of a local representative empowered to receive notices, provide access to OCS mineral and environmental data and information, and comply with orders issued pursuant to the regulations of this part. If there is a change in the designated representative, the Director shall be notified immediately.
(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
(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 develop a comprehensive Delineation, Testing, or Mining Plan. Such activities are those which have no significant adverse impact on the natural resources of the OCS. The lessee shall give notice to the Director at least 30 days prior to initiating the proposed preliminary activities on the lease. The notice shall describe in detail those activities that are to be conducted and the time schedule for conducting those activities.
(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 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.
(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
(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, aquifers, or other natural resources of the OCS; and hazards to public health, safety, and navigation.
(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 written approval of the Director prior to the use of such new or alternative technologies, techniques, procedures, equipment, or activities.
(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
(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)
(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)
(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 §§ 250.194, 250.218, 250.249, and 250.303 of this title.
(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
(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 all operations conducted during each month and present a general summary of the status of leasehold activities. The report shall be submitted each month until the lease is terminated or relinquished unless the Director authorizes omission of the report during an approved suspension of production. The report shall show for each calendar month the location of each mining and processing activity; the number of days operations were conducted; the identity, quantity, quality, and value of each OCS mineral produced, sold, transferred, used or otherwise disposed of; identity, quantity, and quality of an inventory maintained prior to the point of royalty determination; and other information as may be required by the Director.
(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 as the lease continues in force. Should the lessee choose to dispose of original data and information once the lease has expired, said data and information shall be offered to the lessor free of costs and shall, if accepted, become the property of the lessor.
(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
(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 case of default in the performance of the terms and conditions of the lease.
(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
(f) For the purposes of this section there are three areas:
(1) The Gulf of Mexico and the area offshore the Atlantic Ocean;
(2) The area offshore the Pacific Coast States of California, Oregon, Washington, and Hawaii; and
(3) The area offshore the coast of Alaska.
(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.
43 U.S.C. 1331
The authority for this part derives from amendments to subsection 8 of the Outer Continental Shelf Lands Act (OCS Lands Act) (43 U.S.C. 1337), as set forth in section 388(a) of the Energy
(a) Produce or support production, transportation, or transmission of energy from sources other than oil and gas; or
(b) Use, for energy-related purposes or for other authorized marine-related purposes, facilities currently or previously used for activities authorized under the OCS Lands Act.
The purpose of this part is to:
(a) Establish procedures for issuance and administration of leases, right-of-way (ROW) grants, and right-of-use and easement (RUE) grants for renewable energy production on the Outer Continental Shelf (OCS) and RUEs for the alternate use of OCS facilities for energy or marine-related purposes;
(b) Inform you and third parties of your obligations when you undertake activities authorized in this part; and
(c) Ensure that renewable energy activities on the OCS and activities involving the alternate use of OCS facilities for energy or marine-related purposes are conducted in a safe and environmentally sound manner, in conformance with the requirements of subsection 8(p) of the OCS Lands Act, other applicable laws and regulations, and the terms of your lease, ROW grant, RUE grant, or Alternate Use RUE grant.
(d) This part will not convey access rights for oil, gas, or other minerals.
(a) The MMS will ensure that any activities authorized in this part are carried out in a manner that provides for:
(1) Safety;
(2) Protection of the environment;
(3) Prevention of waste;
(4) Conservation of the natural resources of the OCS;
(5) Coordination with relevant Federal agencies (including, in particular, those agencies involved in planning activities that are undertaken to avoid conflicts among users and maximize the economic and ecological benefits of the OCS, including multifaceted spatial planning efforts);
(6) Protection of national security interests of the United States;
(7) Protection of the rights of other authorized users of the OCS;
(8) A fair return to the United States;
(9) Prevention of interference with reasonable uses (as determined by the Secretary or Director) of the exclusive economic zone, the high seas, and the territorial seas;
(10) Consideration of the location of and any schedule relating to a lease or grant under this part for an area of the OCS, and any other use of the sea or seabed;
(11) Public notice and comment on any proposal submitted for a lease or grant under this part; and
(12) Oversight, inspection, research, monitoring, and enforcement of activities authorized by a lease or grant under this part.
(b) The MMS will require compliance with all applicable laws, regulations, other requirements, and the terms of your lease or grant under this part and approved plans. The MMS will approve, disapprove, or approve with conditions any plans, applications, or other documents submitted to MMS for approval under the provisions of this part.
(c) Unless otherwise provided in this part, MMS may give oral directives or decisions whenever prior MMS approval is required under this part. The MMS will document in writing any such oral directives within 10 business days.
(d) The MMS will establish practices and procedures to govern the collection of all payments due to the Federal Government, including any cost recovery fees, rents, operating fees, and other fees or payments. The MMS will do this in accordance with the terms of this part, the leasing notice, the lease or grant under this part, and applicable Minerals Revenue Management regulations or guidance.
(e) The MMS will provide for coordination and consultation with the Governor of any State or the executive of any local government or Indian tribe
(a) The MMS may prescribe or approve departures from these regulations when departures are necessary to:
(1) Facilitate the appropriate activities on a lease or grant under this part;
(2) Conserve natural resources;
(3) Protect life (including human and wildlife), property, or the marine, coastal, or human environment; or
(4) Protect sites, structures, or objects of historical or archaeological significance.
(b) Any departure approved under this section and its rationale must:
(1) Be consistent with subsection 8(p) of the OCS Lands Act;
(2) Protect the environment and the public health and safety to the same degree as if there was no approved departure from the regulations;
(3) Not impair the rights of third parties; and
(4) Be documented in writing.
Except as otherwise authorized by law, it will be unlawful for any person to construct, operate, or maintain any facility to produce, transport, or support generation of electricity or other energy product derived from a renewable energy resource on any part of the OCS, except under and in accordance with the terms of a lease, easement, or ROW issued pursuant to the OCS Lands Act.
As a lessee, applicant, operator, or holder of a ROW grant, RUE grant, or Alternate Use RUE grant, you must:
(a) Design your projects and conduct all activities in a manner that ensures safety and will not cause undue harm or damage to natural resources, including their physical, atmospheric, and biological components to the extent practicable; and take measures to prevent unauthorized discharge of pollutants including marine trash and debris into the offshore environment.
(b) Submit requests, applications, plans, notices, modifications, and supplemental information to MMS as required by this part;
(c) Follow up, in writing, any oral request or notification you made, within 3 business days;
(d) Comply with the terms, conditions, and provisions of all reports and notices submitted to MMS, and of all plans, revisions, and other MMS approvals, as provided in this part;
(e) Make all applicable payments on time;
(f) Comply with the DOI's nonprocurement debarment regulations at 2 CFR part 1400;
(g) Include the requirement to comply with 2 CFR part 1400 in all contracts and transactions related to a lease or grant under this part;
(h) Conduct all activities authorized by the lease or grant in a manner consistent with the provisions of subsection 8(p) of the OCS Lands Act;
(i) Compile, retain, and make available to MMS representatives, within the time specified by MMS, any data and information related to the site assessment, design, and operations of your project; and
(j) Respond to requests from the Director in a timely manner.
(a) You may hold a lease or grant under this part if you can demonstrate that you have the technical and financial capabilities to conduct the activities authorized by the lease or grant and you are a(n):
(1) Citizen or national of the United States;
(2) Alien 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 any State of the United States, the District of Columbia, or any territory or insular possession subject to U.S. jurisdiction;
(4) Association of such citizens, nationals, resident aliens, or corporations;
(5) Executive Agency of the United States as defined in section 105 of Title 5 of the U.S. Code;
(6) State of the United States; and
(7) Political subdivision of States of the United States.
(b) You may not hold a lease or grant under this part or acquire an interest in a lease or grant under this part if:
(1) You or your principals are excluded or disqualified from participating in transactions covered by the Federal nonprocurement debarment and suspension system (2 CFR part 1400), unless MMS explicitly has approved an exception for this transaction;
(2) The MMS determines or has previously determined after notice and opportunity for a hearing that you or your principals have failed to meet or exercise due diligence under any OCS lease or grant; or
(3) The MMS determines or has previously determined after notice and opportunity for a hearing that you:
(i) Remained in violation of the terms and conditions of any lease or grant issued under the OCS Lands Act for a period extending longer than 30 days (or such other period MMS allowed for compliance) after MMS directed you to comply; and
(ii) You took no action to correct the noncompliance within that time period.
(a) You must demonstrate your technical and financial capability to construct, operate, maintain, and terminate/decommission projects for which you are requesting authorization. Documentation can include:
(1) Descriptions of international or domestic experience with renewable energy projects or other types of electric-energy-related projects; and
(2) Information establishing access to sufficient capital to carry out development.
(b) An individual must submit a written statement of citizenship status attesting to U.S. citizenship. It does not need to be notarized nor give the age of individual. A resident alien may submit a photocopy of the Immigration and Naturalization Service form evidencing legal status of the resident alien.
(c) A corporation or association must submit evidence, as specified in the table in paragraph (d) of this section, acceptable to MMS that:
(1) It is qualified to hold leases or grants under this part;
(2) It is authorized to conduct business under the laws of its State;
(3) It is authorized to hold leases or grants on the OCS under the operating rules of its business; and
(4) The persons holding the titles listed are authorized to bind the corporation or association when conducting business with MMS.
(d) Acceptable evidence under paragraph (c) of this section includes, but is not limited to the following:
(e) A local, state, or Federal executive entity must submit a written statement that:
(1) It is qualified to hold leases or grants under this part; and
(2) The person(s) acting on behalf of the entity is authorized to bind the entity when conducting business with us.
(f) The MMS may require you to submit additional information at any time considering your bid or request for a noncompetitive lease.
You must notify MMS within 3 business days after you learn of any action filed alleging that you are insolvent or bankrupt.
You must notify MMS in writing of any merger, name change, or change of business form. You must notify MMS as soon as practicable following the merger, name change, or change in business form, but no later than 120 days after the earliest of either the effective date, or the date of filing the change or action with the Secretary of the State or other authorized official in the State of original registry.
(a) You must submit all plans, applications, reports, or notices required by this part to MMS at the following address: Associate Director, OEMM, Minerals Management Service, MS-4001, 381 Elden Street, Herndon, VA 20170.
(b) Unless otherwise stated, you must submit one paper copy and one electronic copy of all plans, applications, reports, or notices required by this part.
(a) The MMS will charge a processing fee on a case-by-case basis under the procedures in this section with regard to any application or request under this part if we decide at any time that the preparation of a particular document or study is necessary for the application or request and it will have a unique processing cost, such as the preparation of an Environmental Assessment (EA) or Environmental Impact Statement (EIS).
(1) Processing costs will include contract oversight and efforts to review and approve documents prepared by contractors, whether the contractor is paid directly by the applicant or through MMS.
(2) We may apply a standard overhead rate to direct processing costs.
(b) We will assess the ongoing processing fee for each individual application or request according to the following procedures:
(1) Before we process your application or request, we will give you a written estimate of the proposed fee based on reasonable processing costs.
(2) You may comment on the proposed fee.
(3) You may:
(i) Ask for our approval to perform, or to directly pay a contractor to perform, all or part of any document, study, or other activity according to standards we specify, thereby reducing our costs for processing your application or request; or
(ii) Ask to pay us to perform, or contract for, all or part of any document, study, or other activity.
(4) We will then give you the final estimate of the processing fee amount with payment terms and instructions after considering your comments and any MMS-approved work you will do.
(i) If we encounter higher or lower processing costs than anticipated, we will re-estimate our reasonable processing costs following the procedures in paragraphs (b)(1), (b)(2), (b)(3), and (b)(4) of this section, but we will not stop ongoing processing unless you do not pay in accordance with paragraph (b)(5) of this section.
(ii) Once processing is complete, we will refund to you the amount of money that we did not spend on processing costs.
(5)(i) Consistent with the payment and billing terms provided in the final estimate, we will periodically estimate what our reasonable processing costs will be for a specific period and will bill you for that period. Payment is due to us 30 days after you receive your bill. We will stop processing your document if you do not pay the bill by the date payment is due.
(ii) If a periodic payment turns out to be more or less than our reasonable processing costs for the period, we will adjust the next billing accordingly or make a refund. Do not deduct any amount from a payment without our prior written approval.
(6) You must pay the entire fee before we will issue the final document or take final action on your application or request.
(7) You may appeal our estimated processing costs in accordance with the regulations in 43 CFR part 4. We will not process the document further until the appeal is resolved, unless you pay the fee under protest while the appeal is pending. If the appeal results in a decision changing the proposed fee, we will adjust the fee in accordance with paragraph (b)(5)(ii) of this section. If we adjust the fee downward, we will not pay interest.
Terms used in this part have the meanings as defined in this section:
(1) That is, or is proposed to be, the site of gathering, transmitting, or distributing electricity or other energy product, or is otherwise receiving, processing, refining, or transshipping product, or services derived from activities approved under this part;
(2) That is used, or is proposed to be used, as a support base for activities approved under this part; or
(3) In which there is a reasonable probability of significant effect on land or water uses from activities approved under this part.
(1) That is, or is proposed to be, the site of gathering, transmitting, or distributing energy or is otherwise receiving, processing, refining, or transshipping products, or services derived from activities approved under this part;
(2) That is used, or is scheduled to be used, as a support base for activities approved under this part; or
(3) In which there is a reasonable probability of significant effect on land or water uses from activities approved under this part.
(a) The MMS will make data and information available in accordance with the requirements and subject to the limitations of the Freedom of Information Act (FOIA) (5 U.S.C. 552), the regulations contained in 43 CFR part 2 (Records and Testimony).
(b) The MMS will not release such data and information that we have determined is exempt from disclosure under exemption 4 of FOIA. We will review such data and information and objections of the submitter by the following schedule to determine whether release at that time will result in substantial competitive harm or disclosure of trade secrets.
(c) After considering any objections from the submitter, if we determine that release of such data and information will result in:
(1) No substantial competitive harm or disclosure of trade secrets, then the data and information will be released.
(2) Substantial competitive harm or disclosure of trade secrets, then the data and information will not be released at that time but will be subject to further review every 3 years thereafter.
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in 30 CFR part 285 under 44 U.S.C. 3501,
(b) Respondents are primarily renewable energy applicants, lessees, ROW grant holders, RUE grant holders, Alternate Use RUE grant holders, and operators. The requirement to respond to the information collection in this part is mandated under subsection 8(p) of the OCS Lands Act. Some responses are also required to obtain or retain a benefit, or may be voluntary.
(c) The Paperwork Reduction Act of 1995 (44 U.S.C. 3501
(d) Comments regarding any aspect of the collections of information under this part, including suggestions for reducing the burden should be sent to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 5438, 1849 C Street, NW., Washington, DC 20240.
(e) The MMS is collecting this information for the reasons given in the following table:
(a) The 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) The MMS will publish, as a rule, any changes in the documents incorporated by reference in the
(2) The MMS may amend by rule the list of industry standards incorporated by reference of the document effective without prior opportunity for public comment when MMS determines 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
(3) The MMS may make a rule, effective immediately, amending the list of industry standards incorporated by reference if it determines good cause exists for doing so under 5 U.S.C. 553.
(b) The MMS is incorporating 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 specific addition and addendum cited in this section.
(c) You may comply with a later edition of a specific document incorporated by reference, only if:
(1) You show that complying with the later edition provides a degree of protection, safety, or performance equal to or better than what 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, 703-787-1605; or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to:
(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) The Director may, from time to time, and at his discretion, solicit information from industry and other relevant stakeholders (including State and local agencies), as necessary, to evaluate the state of the offshore renewable energy industry, including the identification of potential challenges or obstacles to its continued development. Such requests for information may relate to the identification of environmental, technical, regulatory, or economic matters that promote or detract from continued development of renewable energy technologies on the OCS. From the information received, the Director may evaluate potential refinements to the OCS Alternative Energy Program that promote development of the industry in a safe and environmentally responsible manner, and that ensure fair value for use of the Nation's OCS.
(b) The MMS may make such requests for information on a regional basis, and may tailor the requests to specific types of renewable energy technologies.
(c) The MMS will publish such requests for information by the Director in the
(a) Any party adversely affected by an MMS official's final decision or order issued under the regulations of this part may appeal that decision or order to the Interior Board of Land Appeals. The appeal must conform with the procedures found in 30 CFR part 290 and 43 CFR part 4, subpart E. Appeal of a final decision for bid acceptance is covered under paragraph (c) of this section.
(b) A decision will remain in full force and effect during the period in which an appeal may be filed and during an appeal, unless a stay is granted pursuant to 43 CFR part 4.
(c) Our decision on a bid is the final action of the Department, except that an unsuccessful bidder may apply for reconsideration by the Director.
(1) A bidder whose bid we reject may file a written request for reconsideration with the Director within 15 days of the date of the receipt of the notice of rejection, accompanied by a statement of reasons, with one copy to us. The Director will respond in writing either affirming or reversing the decision.
(2) The delegation of review authority given to the Office of Hearings and Appeals does not apply to decisions on high bids for leases or grants under this part.
(a) A lease issued under this part grants the lessee the right, subject to obtaining the necessary approvals, including but not limited to those required under the FERC hydrokinetic licensing process, and complying with all provisions of this part, to occupy, and install and operate facilities on, a designated portion of the OCS for the purpose of conducting:
(1) Commercial activities; or
(2) Other limited activities that support, result from, or relate to the production of energy from a renewable energy source.
(b) A lease issued under this part confers on the lessee the right to one or more project easements without further competition for the purpose of installing gathering, transmission, and distribution cables; pipelines; and appurtenances on the OCS as necessary for the full enjoyment of the lease.
(1) You must apply for the project easement as part of your COP or GAP, as provided under subpart F of this part; and
(2) The MMS will incorporate your approved project easement in your lease as an addendum.
(c) A commercial lease issued under this part may be developed in phases, with MMS approval as provided in § 285.629.
The MMS will issue leases on a competitive basis, as provided under §§ 285.210 through 285.225. However, if we determine after public notice of a proposed lease that there is no competitive interest, we will issue leases noncompetitively, as provided under §§ 285.230 and 285.232. We will issue leases on forms approved by MMS and will include terms, conditions, and stipulations identified and developed through the process set forth in §§ 285.211 and 285.231.
The MMS may issue leases on the OCS for the assessment and production of renewable energy and may authorize a combination of specific activities. We may issue commercial leases or limited leases.
For leases issued under this part, through either the competitive or noncompetitive process, MMS prior to issuing the lease, will coordinate and consult with relevant Federal agencies (including, in particular, those agencies involved in planning activities that are undertaken to avoid conflicts among users and maximize the economic and ecological benefits of the OCS, including multifaceted spatial planning efforts), the Governor of any affected State, the executive of any affected local government, and any affected Indian tribe, as directed by subsections 8(p)(4) and (7) of the OCS Lands Act or other relevant Federal laws. Federal statutes that require us to consult with or respond to findings include the Endangered Species Act (ESA), and the Magnuson-Stevens Fishery Conservation and Management Act (MSA).
The MMS may offer any appropriately platted area of the OCS, as provided in § 285.205, for a renewable energy lease, except any area within the exterior boundaries of any unit of the National Park System, National Wildlife Refuge System, National Marine Sanctuary System, or any National Monument.
The MMS will prepare leasing maps and official protraction diagrams of areas of the OCS. The areas included in each lease will be in accordance with the appropriate leasing map or official protraction diagram.
(a) The MMS will determine the size for each lease based on the area required to accommodate the anticipated activities. The processes leading to both competitive and noncompetitive issuance of leases will provide public notice of the lease size adopted. We will delineate leases by using mapped OCS blocks or portions, or aggregations of blocks.
(b) The lease size includes the minimum area that will allow the lessee sufficient space to develop the project and manage activities in a manner that is consistent with the provisions of this part. The lease may include whole lease blocks or portions of a lease block.
The MMS may publish in the
The MMS will use auctions to award leases on a competitive basis. We will publish details of the process to be employed for each lease sale auction in the
(a)
(1) Request comments on areas which should receive special consideration and analysis;
(2) Request comments concerning geological conditions (including bottom hazards); archaeological sites on the seabed or nearshore; multiple uses of the proposed leasing area (including navigation, recreation, and fisheries); and other socioeconomic, biological, and environmental information; and
(3) Suggest areas to be considered by the respondents for leasing.
(b)
(1) We may consider for lease those areas nominated in response to the Call for Information and Nominations, together with other areas that MMS determines are appropriate for leasing.
(2) We will evaluate the potential effect of leasing on the human, marine, and coastal environments, and develop measures to mitigate adverse impacts, including lease stipulations.
(3) We will consult to develop measures, including lease stipulations and conditions, to mitigate adverse impacts on the environment; and
(4) We may hold public hearings on the environmental analysis after appropriate notice.
(c)
(d)
The MMS may decide to end the competitive process before the Final Sale Notice if we have reason to believe that competitors have withdrawn and competition no longer exists. We will issue a second public notice of Request for Interest and consider comments received to confirm that there is no competitive interest.
(a) If, after reviewing comments in response to the notice of Request for Interest, MMS determines that there is no competitive interest in the lease area, and one party wishes to acquire a lease, we will discontinue the competitive process and will proceed with the noncompetitive process set forth in § 285.231(d) through (i). Under the noncompetitive process, the acquisition fee specified in § 285.502(a) must be submitted with the Site Assessment Plan (SAP) or GAP.
(b) If, after reviewing comments in response to the notice of Request for Interest, MMS determines that competitive interest in the lease area continues to exist, we will continue with the competitive process set forth in § 285.211 through 285.225.
If you are a potential lessee, when you respond to a Request for Interest or a Call, your response must include the following items:
(a) The area of interest for a possible lease.
(b) A general description of your objectives and the facilities that you would use to achieve those objectives.
(c) A general schedule of proposed activities, including those leading to commercial operations.
(d) Available and pertinent data and information concerning renewable energy and environmental conditions in the area of interest, including energy and resource data and information used to evaluate the area of interest. The
(e) Documentation showing that you are qualified to hold a lease, as specified in § 285.107.
(f) Any other information requested by MMS in the
The MMS will use the information received in response to the Requests or Calls to:
(a) Identify the lease area;
(b) Develop options for the environmental analysis and leasing provisions (stipulations, payments, terms, and conditions); and
(c) Prepare appropriate documentation to satisfy applicable Federal requirements, such as NEPA, CZMA, the ESA, and the MSA.
The MMS will offer the areas for leasing determined through the process set forth in § 285.211 of this part. We will not accept nominations after the Call for Information and Nominations closes.
For each competitive lease sale, MMS will publish a Proposed Sale Notice and a Final Sale Notice in the
(a) The area available for leasing.
(b) Proposed and final lease provisions and conditions, including, but not limited to:
(1) Lease size;
(2) Lease term;
(3) Payment requirements;
(4) Performance requirements; and
(5) Site-specific lease stipulations.
(c) Auction details, including:
(1) Bidding procedures and systems;
(2) Minimum bid;
(3) Deposit amount;
(4) The place and time for filing bids and the place, date, and hour for opening bids;
(5) Lease award method; and
(6) Bidding or application instructions.
(d) The official MMS lease form to be used or a reference to that form.
(e) Criteria MMS will use to evaluate competing bids or applications and how the criteria will be used in decision-making for awarding a lease.
(f) Award procedures, including how and when MMS will award leases and how MMS will handle unsuccessful bids or applications.
(g) Procedures for appealing the lease issuance decision.
(h) Execution of the lease instrument.
(a) Except as provided in § 285.231, we will hold competitive auctions to award renewable energy leases and will use one of the following auction formats, as determined through the lease sale process and specified in the Proposed Sale Notice and in the Final Sale Notice:
(b) You must submit your bid and a deposit as specified in §§ 285.500 and 285.501 to cover the bid for each lease area, according to the terms specified in the Final Sale Notice.
(a) For commercial leases, we will specify minimum bids in the Final Sale Notice and use one of the following bidding systems, as specified in the Proposed Sale Notice and in the Final Sale Notice:
(b) For limited leases, the bid variable will be a cash bonus, with a minimum bid as we specify in the Final Sale Notice.
(a) If sealed bidding is used:
(1) We open the sealed bids at the place, date, and hour specified in the Final Sale Notice for the sole purpose of publicly announcing and recording the bids. We do not accept or reject any bids at that time.
(2) We reserve the right to reject any and all high bids, including a bid for any proposal submitted under the multiple-factor bidding format, regardless of the amount offered or bidding system used. The reasons for the rejection of a winning bid may include, but are not necessarily limited to, insufficiency, illegality, anti-competitive behavior, administrative error, and the presence of unusual bidding patterns. We intend to accept or reject all high bids within 90 days, but we may extend that time if necessary.
(b) If we use ascending bidding, we may, in the Final Sale Notice, reserve the right to accept the winning bid solely based on its being the highest bid submitted by a qualified bidder (qualified to be an OCS lessee under § 285.107).
(c) If we use two-stage bidding and the auction concludes with
(i) an ascending bidding stage, the winning bid will be determined as stated in paragraph (b) of this section; or
(ii) a sealed bidding stage, the winning bid will be determined as stated in paragraph (a) of this section.
(d) If we use multiple-factor bidding, determination of the winning bid for any proposal submitted will be made by a panel composed of members selected by MMS. The details of the process will be described in the Final Sale Notice.
(e) We will send a written notice of our decision to accept or reject bids to all bidders whose deposits we hold.
(a) Unless otherwise specified in the Final Sale Notice, except in the first stage of a two-stage bidding auction, if more than one bidder on a lease submits the same high bid amount, the winning bidder will be determined by a further round or stage of bidding as described in the Final Sale Notice.
(b) The winning bidder will be subject to final confirmation following determination of bid adequacy.
If we accept your bid, we will send you a notice with three copies of the lease form.
(a) Within 10 business days after you receive the lease copies, you must:
(1) Execute the lease;
(2) File financial assurance as required under §§ 285.515 through 285.537; and
(3) Pay the balance of the bonus bid as specified in the lease sale notice.
(b) Within 45 days after you receive the lease copies, you must pay the first 6 months rent as required in § 285.503.
(c) When you execute three copies of the lease and return the copies to us, we will execute the lease on behalf of the United States and send you one fully executed copy.
(d) You will forfeit your deposit if you do not execute and return the lease within 10 business days of receipt, or otherwise fail to comply with applicable regulations or terms of the Final Sale Notice.
(e) We may extend the 10 business day time period for executing and returning the lease if we determine the delay to be caused by events beyond your control.
(f) We reserve the right to withdraw an OCS area in which we have held a lease sale before you and MMS execute the lease in that area. If we exercise this right, we will refund your bid deposit, without interest.
(g) If the awarded lease is executed by an agent acting on behalf of the bidder, the bidder must submit, along with the executed lease, written evidence that the agent is authorized to act on behalf of the bidder.
(h) The MMS will consider the highest submitted qualified bid to be the winning bid when bidding occurs under the systems described in §§ 285.221(a)(1) through (5). We will determine the winning bid for proposals submitted under
(a) If we reject your bid, we will provide a written statement of the reasons and refund any money deposited with your bid, without interest.
(b) You may ask the MMS Director for reconsideration, in writing, within 15 business days of bid rejection, under § 285.118(c)(1). We will send you a written response either affirming or reversing the rejection.
You may submit an unsolicited request for a commercial lease or a limited lease under this part. Your unsolicited request must contain the following information:
(a) The area you are requesting for lease.
(b) A general description of your objectives and the facilities that you would use to achieve those objectives.
(c) A general schedule of proposed activities including those leading to commercial operations.
(d) Available and pertinent data and information concerning renewable energy and environmental conditions in the area of interest, including energy and resource data and information used to evaluate the area of interest. The MMS will withhold trade secrets and commercial or financial information that is privileged or confidential from public disclosure under exemption 4 of the FOIA and as provided in § 285.113.
(e) If available from the appropriate State or local government authority, a statement that the proposed activity conforms with State and local energy planning requirements, initiatives, or guidance.
(f) Documentation showing that you meet the qualifications to become a lessee, as specified in § 285.107.
(g) An acquisition fee, as specified in § 285.502(a).
(a) The MMS will consider unsolicited requests for a lease on a case-by-case basis and may issue a lease noncompetitively in accordance with this part. We will not consider an unsolicited request for a lease under this part that is proposed in an area of the OCS that is scheduled for a lease sale under this part.
(b) The MMS will issue a public notice of a request for interest relating to your proposal and consider comments received to determine if competitive interest exists.
(c) If MMS determines that competitive interest exists in the lease area:
(1) The MMS will proceed with the competitive process set forth in §§ 285.210 through 285.225;
(2) If you submit a bid for the lease area in a competitive lease sale, your acquisition fee will be applied to the deposit for your bonus bid; and
(3) If you do not submit a bid for the lease area in a competitive lease sale, MMS will not refund your acquisition fee.
(d) If MMS determines that there is no competitive interest in a lease:
(1) We will publish in the
(2) You must submit within 60 days of the date of the notice to MMS:
(i) For a commercial lease, a SAP, as described in §§ 285.605 through 285.613; or
(ii) For a limited lease, a GAP, as described in §§ 285.640 through 285.648.
(e) The MMS will coordinate and consult with affected Federal agencies, State, and local governments, and affected Indian tribes in the review of noncompetitive lease requests and associated plans.
(f) If we approve or approve with conditions your SAP or GAP, we may offer you a noncompetitive lease.
(g) If you accept the terms and conditions of the lease, then we will issue the lease, and you must comply with all terms and conditions of your lease and all applicable provisions of this
(1) Within 10 business days after you receive the lease copies you must:
(i) Execute the lease;
(ii) File financial assurance as required under §§ 285.515 through 285.537; and
(2) Within 45 days after you receive the lease copies, you must pay the first 6-months rent, as required in § 285.503.
(h) The MMS will publish in the
(i) If you do not accept the terms and conditions, MMS will not issue a lease, and we will not refund your acquisition fee.
(a) If you submit an area of interest for a possible lease and MMS receives no competing submissions in response to the RFI or Call, we may inform you that there does not appear to be competitive interest, and ask if you wish to proceed with acquiring a lease.
(b) If you wish to proceed with acquiring a lease, you must submit your acquisition fee as specified in § 285.502(a).
(c) After receiving the acquisition fee, BOEMRE will follow the process outlined in § 285.231(d) through (i).
(a) For commercial leases, the lease terms and applicable automatic extensions are as shown in the following table:
(b) If you do not timely submit a SAP, COP, or SAP/COP, as appropriate, you may request additional time to extend the preliminary or site assessment term of your commercial lease that includes a revised schedule for submission of the plan, as appropriate.
(a) For limited leases, the lease terms are as shown in the following table:
(b) If you do not timely submit a GAP, you may request additional time to extend the preliminary term of your limited lease that includes a revised schedule for submission of a GAP.
(a) A lease issued under this part must be dated and becomes effective as of the first day of the month following the date a lease is signed by the lessor.
(b) If the lessee submits a written request and MMS approves, a lease may be dated and become effective the first day of the month in which it is signed by the lessor.
(a) The Director may issue OCS leases, ROW grants, and RUE grants to a Federal agency or a State for renewable energy research activities that support the future production, transportation, or transmission of renewable energy.
(b) In issuing leases, ROW grants, and RUE grants to a Federal agency or a State on the OCS for renewable energy research activities under this provision, MMS will coordinate and consult with other relevant Federal agencies, any other affected State(s), affected local government executives, and affected Indian tribes.
(c) The MMS may issue leases, RUEs, and ROWs for research activities managed by a Federal agency or a State only in areas for which the Director has determined, after public notice and opportunity to comment, that no competitive interest exists.
(d) The Director and the head of the Federal agency or the Governor of a requesting State, or their authorized representatives, will negotiate the terms and conditions of such renewable energy leases, RUEs, or ROWs under this provision on a case-by-case basis. The framework for such negotiations, and standard terms and conditions of such leases, RUEs, or ROWs may be set forth in a memorandum of agreement (MOA) or other agreement between MMS and a Federal agency or a State. The MOA must include the agreement of the head of the Federal agency or
(e) Any lease, RUE, or ROW that MMS issues to a Federal agency or to a State that authorizes access to an area of the OCS for research activities managed by a Federal agency or a State must include:
(1) Requirements to comply with all applicable Federal laws; and
(2) Requirements to comply with these regulations, except as otherwise provided in the lease or grant.
(f) The MMS will issue a public notice of any lease, RUE, ROW issued to a Federal agency or to a State, or an approved MOA for such research activities.
(g) The MMS will not charge any fees for the purpose of ensuring a fair return for the use of such research areas on the OCS.
(a) An ROW grant authorizes the holder to install on the OCS cables, pipelines, and associated facilities that involve the transportation or transmission of electricity or other energy product from renewable energy projects.
(b) An RUE grant authorizes the holder to construct and maintain facilities or other installations on the OCS that support the production, transportation, or transmission of electricity or other energy product from any renewable energy resource.
(c) You do not need an ROW grant or RUE grant for a project easement authorized under § 285.200(b) to serve your lease.
(a) An ROW grant:
(1) Includes the full length of the corridor on which a cable, pipeline, or associated facility is located;
(2) Is 200 feet (61 meters) in width, centered on the cable or pipeline, unless safety and environmental factors during construction and maintenance of the associated cable or pipeline require a greater width; and
(3) For the associated facility, is limited to the area reasonably necessary for a power or pumping station or other accessory facility.
(b) An RUE grant includes the site on which a facility or other structure is located and the areal extent of anchors, chains, and other equipment associated with a facility or other structure. The specific boundaries of an RUE will be determined by MMS on a case-by-case basis and set forth in each RUE grant.
(a) To acquire an ROW grant or RUE grant you must provide evidence that you meet the qualifications as required in § 285.107.
(b) An ROW grant or RUE grant is subject to the following conditions:
(1) The rights granted will not prevent the granting of other rights by the United States, either before or after the granting of the ROW or RUE, provided that any subsequent authorization issued by MMS in the area of a previously issued ROW grant or RUE grant may not unreasonably interfere with activities approved or impede existing operations under such a grant; and
(2) The holder agrees that the United States, its lessees, or other ROW grant or RUE grant holders may use or occupy any part of the ROW grant or RUE grant not actually occupied or necessarily incident to its use for any necessary activities.
Your ROW grant or RUE grant will remain in effect for as long as the associated activities are properly maintained and used for the purpose for which the grant was made, unless otherwise expressly stated in the grant.
You must submit to MMS one paper copy and one electronic copy of a request for a new or modified ROW grant or RUE grant. You must submit a separate request for each ROW grant or RUE grant you are requesting. The request must contain the following information:
(a) The area you are requesting for a ROW grant or RUE grant.
(b) A general description of your objectives and the facilities that you would use to achieve those objectives.
(c) A general schedule of proposed activities.
(d) Pertinent information concerning environmental conditions in the area of interest.
The MMS will consider requests for ROW grants and RUE grants on a case-by-case basis and may issue a grant competitively, as provided in § 285.308, or noncompetitively if we determine after public notice that there is no competitive interest. The MMS will coordinate and consult with relevant Federal agencies, with the Governor of any affected State, and the executive of any affected local government.
(a) In response to an unsolicited request for a ROW grant or RUE grant, the MMS will first determine if there is competitive interest, as provided in § 285.307.
(b) If MMS determines that there is no competitive interest in a ROW grant or RUE grant, we will:
(1) In consultation with you, establish the terms and conditions for the grant;
(2) Require you to submit a GAP, as described in §§ 285.640 through 285.648, within 60 days of the determination of no competitive interest; and
(3) Evaluate your request for a noncompetitive grant and GAP simultaneously.
(c) If we award your ROW grant or RUE grant competitively, you must submit and receive MMS approval of your GAP, as provided in §§ 285.640 through 285.648.
To determine whether or not there is competitive interest:
(a) We will publish a public notice, describing the parameters of the project, to give affected and interested parties an opportunity to comment on the proposed ROW grant or RUE grant area.
(b) We will evaluate any comments received on the notice and make a determination of the level of competitive interest.
(a) If MMS determines that there is competitive interest, we will:
(1) Publish a notice of each grant auction in the
(2) Conduct a competitive auction for issuing the ROW grant or RUE grant. The auction process for ROW grants and RUE grants will be conducted following the same process for leases set forth in §§ 285.211 through 285.225.
(b) If you are the successful bidder in an auction, you must pay the first year's rent, as provided in § 285.316.
If we approve or approve with conditions your GAP, we may offer you a noncompetitive grant.
(a) If you accept the terms and conditions of the grant, then we will issue the grant, and you must comply with all terms and conditions of your grant and all applicable provisions of this part.
(b) If you do not accept the terms and conditions, MMS will not issue a grant.
Your ROW grant or RUE grant becomes effective on the date established
(a) You must make a deposit, as required in § 285.501(a), regardless of whether the auction is a sealed-bid, oral, electronic, or other auction format. The MMS will specify in the sale notice the official to whom you must submit the payment, the time by which the official must receive the payment, and the forms of acceptable payment.
(b) If your high bid is rejected, we will provide a written statement of reasons.
(c) For all rejected bids, we will refund, without interest, any money deposited with your bid.
Before we issue the ROW grant or RUE grant, you must pay:
(a) Any balance on accepted high bids to MMS, as provided in the sale notice.
(b) An annual rent for the first year of the grant, as specified in § 285.508.
(a) The MMS may take appropriate corrective action under this part if you fail to comply with applicable provisions of Federal law, the regulations in this part, other applicable regulations, any order of the Director, the provisions of a lease or grant issued under this part, or the requirements of an approved plan or other approval under this part.
(b) The MMS may issue to you a notice of noncompliance if we determine that there has been a violation of the regulations in this part, any order of the Director, or any provision of your lease, grant or other approval issued under this part. When issuing a notice of noncompliance, MMS will serve you at your last known address.
(c) A notice of noncompliance will tell you how you failed to comply with this part, any order of the Director, and/or the provisions of your lease, grant or other approval, and will specify what you must do to correct the noncompliance and the time limits within which you must act.
(d) Failure of a lessee, operator, or grant holder under this part to take the actions specified in a notice of noncompliance within the time limit specified provides the basis for MMS to issue a cessation order as provided in § 285.401, and/or a cancellation of the lease or grant as provided in § 285.437.
(e) If the MMS determines that any incident of noncompliance poses an imminent threat of serious or irreparable damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance, MMS may include with its notice of noncompliance an order directing you to take immediate remedial action to alleviate threats and to abate the violation and, when appropriate, a cessation order.
(f) The MMS may assess civil penalties, as authorized by section 24 of the OCS Lands Act, if you fail to comply with any provision of this part or any term of a lease, grant, or order issued under the authority of this part, after notice of such failure and expiration of any reasonable period allowed for corrective action. Civil penalties will be determined and assessed in accordance with the procedures set forth in 30 CFR part 250, subpart N.
(g) You may be subject to criminal penalties as authorized by section 24 of the OCS Lands Act.
(a) The MMS may issue a cessation order during the term of your lease or grant when you fail to comply with an applicable law; regulation; order; or provision of a lease, grant, plan, or other MMS approval under this part. Except as provided in § 285.400(e), MMS
(b) A cessation order will set forth what measures you are required to take, including reports you are required to prepare and submit to MMS, to receive approval to resume activities on your lease or grant.
(a) Upon receiving a cessation order, you must cease all activities on your lease or grant, as specified in the order. The MMS may authorize certain activities during the period of the cessation order.
(b) A cessation order will last for the period specified in the order or as otherwise specified by MMS. If MMS determines that the circumstances giving rise to the cessation order cannot be resolved within a reasonable time period, the Secretary may initiate cancellation of your lease or grant, as provided in § 285.437.
(c) A cessation order does not extend the term of your lease or grant for the period you are prohibited from conducting activities.
(d) You must continue to make all required payments on your lease or grant during the period a cessation order is in effect.
(a) If you intend to designate an operator who is not the lessee or grant holder, you must identify the proposed operator in your SAP (under § 285.610(a)(3)), COP (under § 285.626(b)(2)), or GAP (under § 285.645(b)(3)), as applicable. If no operator is designated in a SAP, COP, or GAP, MMS will deem the lessee or grant holder to be the operator.
(b) An operator must be designated in any SAP, COP, or GAP if there is more than one lessee or grant holder for any individual lease or grant.
(c) Once approved in your plan, the designated operator is authorized to act on your behalf and required to perform activities necessary to comply with the OCS Lands Act, the lease or grant, and the regulations in this part.
(d) You, or your designated operator, must immediately provide MMS with a written notification of change of address of the lessee or operator.
(e) If there is a change in the designated operator, you must provide written notice to MMS and identify the new designated operator within 72 hours on a form approved by MMS. The lessee(s) or grantee(s) is the operator and responsible for compliance until MMS approves designation of the new operator.
(f) Designation of an operator under any lease or grant issued under this part does not relieve the lessee or grant holder of its obligations under this part or its lease or grant.
(g) A designated operator performing activities on the lease must comply with all regulations governing those activities and may be held liable or penalized for any noncompliance during the time it was operator, notwithstanding its subsequent resignation.
(a) When you are not the sole lessee or grantee, you and your co-lessee(s) or co-grantee(s) are jointly and severally responsible for fulfilling your obligations under the lease or grant and the provisions of this part, unless otherwise provided in these regulations.
(b) If your designated operator fails to fulfill any of your obligations under the lease or grant and this part, MMS may require you or any or all of your co-lessees or co-grantees to fulfill those obligations or other operational obligations under the OCS Lands Act, the lease, grant, or the regulations.
(c) Whenever the regulations in this part require the lessee or grantee to conduct an activity in a prescribed manner, the lessee or grantee and operator (if one has been designated) are jointly and severally responsible for complying with the regulations.
(a) You may assign all or part of your lease or grant interest, including record title, subject to MMS approval under this subpart. Each instrument that creates or transfers an interest must describe the entire tract or describe by officially designated subdivisions the interest you propose to create or transfer.
(b) You may assign a lease or grant interest by submitting one paper copy and one electronic copy of an assignment application to MMS. The assignment application must include:
(1) The MMS-assigned lease or grant number;
(2) A description of the geographic area or undivided interest you are assigning;
(3) The names of both the assignor and the assignee, if applicable;
(4) The names and telephone numbers of the contacts for both the assignor and the assignee;
(5) The names, titles, and signatures of the authorizing officials for both the assignor and the assignee;
(6) A statement that the assignee agrees to comply with and to be bound by the terms and conditions of the lease or grant;
(7) The qualifications of the assignee to hold a lease or grant under § 285.107; and
(8) A statement on how the assignee will comply with the financial assurance requirements of §§ 285.515 through 285.537. No assignment will be approved until the assignee provides the required financial assurance.
(c) If you submit an application to assign a lease or grant, you will continue to be responsible for payments that are or become due on the lease or grant until the date MMS approves the assignment.
(d) The assignment takes effect on the date MMS approves your application.
(e) You do not need to request an assignment for mergers, name changes, or changes of business form. You must notify MMS of these events under § 285.109.
(a) You must request approval of each assignment on a form approved by MMS, and submit originals of each instrument that creates or transfers ownership of record title or certified copies thereof within 90 days after the last party executes the transfer agreement.
(b) Any assignee will be subject to all the terms and conditions of your original lease or grant, including the requirement to furnish financial assurance in the amount required in §§ 285.515 through 285.537.
(c) The assignee must submit proof of eligibility and other qualifications specified in § 285.107.
(d) Persons executing on behalf of the assignor and assignee must furnish evidence of authority to execute the assignment.
As assignor, you are liable for all obligations, monetary and nonmonetary, that accrued under your lease or grant before MMS approves your assignment. Our approval of the assignment does not relieve you of these accrued obligations. The MMS may require you to bring the lease or grant into compliance to the extent the obligation accrued before the effective date of your assignment if your assignee or subsequent assignees fail to perform any obligation under the lease or grant.
(a) As assignee, you are liable for all lease or grant obligations that accrue after MMS approves the assignment. As assignee, you must comply with all the terms and conditions of the lease or grant and all applicable regulations, remedy all existing environmental and operational problems on the lease or grant, and comply with all decommissioning requirements under subpart I of this part.
(b) Assignees are bound to comply with each term or condition of the lease or grant and the regulations in
(a) A suspension is an interruption of the term of your lease or grant that may occur:
(1) As approved by MMS at your request, as provided in § 285.416; or
(2) As ordered by MMS, as provided in § 285.417.
(b) A suspension extends the term of your lease or grant for the length of time the suspension is in effect.
(c) Activities may not be conducted on your lease or grant during the period of a suspension except as expressly authorized by MMS under the terms of the suspension.
You must submit a written request to MMS that includes the following information no later than 90 days prior to the expiration of your appropriate lease or grant term:
(a) The reasons you are requesting suspension of your lease or grant term, and the length of additional time requested.
(b) An explanation of why the suspension is necessary in order to ensure full enjoyment of your lease or grant and why it is in the lessor's or grantor's interest to approve the suspension.
(c) If you do not timely submit a SAP, COP, or GAP, as required, you may request a suspension to extend the preliminary or site assessment term of your lease or grant that includes a revised schedule for submission of a SAP, COP, or GAP, as appropriate.
(d) Any other information MMS may require.
(a) The MMS may order a suspension under the following circumstances:
(1) When necessary to comply with judicial decrees prohibiting some or all activities under your lease;
(2) When continued activities pose an imminent threat of serious or irreparable harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance; or
(3) When the suspension is necessary for reasons of national security or defense.
(b) If MMS orders a suspension under paragraph (a)(2) of this section, and if you wish to resume activities, we may require you to conduct a site-specific study that evaluates the cause of the harm, the potential damage, and the available mitigation measures. Other requirements and actions may occur:
(1) You may be required to pay for the study;
(2) You must furnish one paper copy and one electronic copy of the study and results to us;
(3) We will make the results available to other interested parties and to the public; and
(4) We will use the results of the study and any other information that become available:
(i) To decide if the suspension order can be lifted; and
(ii) To determine any actions that you must take to mitigate or avoid any damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance.
(a) The MMS will issue a suspension order orally or in writing.
(b) The MMS will send you a written suspension order as soon as practicable after issuing an oral suspension order.
(c) The written order will explain the reasons for its issuance and describe the effect of the suspension order on your lease or grant and any associated
You must comply with the terms of a suspension order upon receipt and take any action prescribed within the time set forth therein.
(a) While MMS evaluates your request for a suspension under § 285.416, you must continue to fulfill your payment obligation until the end of the original term of your lease or grant. If our evaluation goes beyond the end of the original term of your lease or grant, the term of your lease or grant will be extended for the period of time necessary for MMS to complete its evaluation of your request, but you will not be required to make payments during the time of the extension.
(b) If MMS approves your request for a suspension, as provided in § 285.416, we may suspend your payment obligation, as appropriate for the term that is suspended, depending on the reasons for the requested suspension.
(c) If MMS orders a suspension, as provided in § 285.417, your payments, as appropriate for the term that is suspended, will be waived during the suspension period.
A suspension will be in effect for the period specified by MMS.
(a) The MMS will not approve a suspension request pursuant to § 285.416 for a period longer than 2 years.
(b) If MMS determines that the circumstances giving rise to a suspension ordered under § 285.417 cannot be resolved within 5 years, the Secretary may initiate cancellation of the lease or grant, as provided in § 285.437.
You may request renewal of the operations term of your lease or the original authorized term of your grant. The MMS, at its discretion, may approve a renewal request to conduct substantially similar activities as were originally authorized under the lease or grant. The MMS will not approve a renewal request that involves development of a type of renewable energy not originally authorized in the lease or grant. The MMS may revise or adjust payment terms of the original lease, as a condition of lease renewal.
(a) You must request a renewal from MMS:
(1) No later than 180 days before the termination date of your limited lease or grant.
(2) No later than 2 years before the termination date of the operations term of your commercial lease.
(b) You must submit to MMS all information we request pertaining to your lease or grant and your renewal request.
The MMS will set the term of a renewal at the time of renewal on a case-by-case basis.
(a) For commercial leases, a renewal term will not exceed the original operations term unless a longer term is negotiated by the applicable parties.
(b) For limited leases, a renewal term will not exceed the original operations term.
(c) For RUE and ROW grants, a renewal will continue for as long as the associated activities are conducted and facilities properly maintained and used for the purpose for which the grant was made, unless otherwise expressly stated.
If you timely request a renewal:
(a) You may continue to conduct activities approved under your lease or grant under the original terms and conditions for as long as your request is pending decision by MMS.
(b) You may request a suspension of your lease or grant, as provided in § 285.416, while we consider your request.
(c) For the period MMS considers your request for renewal, you must continue to make all payments in accordance with the original terms and conditions of your lease or grant.
The MMS will consider the following criteria in deciding whether to renew a lease or grant:
(a) Design life of existing technology.
(b) Availability and feasibility of new technology.
(c) Environmental and safety record of the lessee or grantee.
(d) Operational and financial compliance record of the lessee or grantee.
(e) Competitive interest and fair return considerations.
(f) Effects of the lease or grant on generation capacity and reliability within the regional electrical distribution and transmission system.
Your lease or grant terminates on whichever of the following dates occurs first:
(a) The expiration of the applicable term of your lease or grant, unless your term is automatically extended under §§ 285.235 or 285.236, a request for renewal of your lease or grant is pending a decision by MMS, or your lease or grant is suspended or renewed as provided in this subpart;
(b) A cancellation, as set forth in § 285.437; or
(c) Relinquishment, as set forth in § 285.435.
(a) After your lease or grant terminates, you must:
(1) Make all payments due, including any accrued rentals and deferred bonuses; and
(2) Perform any other outstanding obligations under the lease or grant within 6 months.
(b) Within 2 years following termination of a lease or grant, you must remove or dispose of all facilities, installations, and other devices permanently or temporarily attached to the seabed on the OCS in accordance with a plan or application approved by MMS under subpart I of this part.
(c) If you fail to comply with your approved decommissioning plan or application:
(1) The MMS may call for the forfeiture of your financial assurance; and
(2) You remain liable for removal or disposal costs and responsible for accidents or damages that might result from such failure.
(a) You may surrender the lease or grant, or an officially designated subdivision thereof, by filing one paper copy and one electronic copy of a relinquishment application with MMS. A relinquishment takes effect on the date we approve your application, subject to the continued obligation of the lessee and the surety to:
(1) Make all payments due on the lease or grant, including any accrued rent and deferred bonuses;
(2) Decommission all facilities on the lease or grant to be relinquished to the satisfaction of MMS; and
(3) Perform any other outstanding obligations under the lease or grant.
(b) Your relinquishment application must include:
(1) Name;
(2) Contact name;
(3) Telephone number;
(4) Fax number;
(5) E-mail address;
(6) The MMS-assigned lease or grant number, and, if applicable, the name of any facility;
(7) A description of the geographic area you are relinquishing;
(8) The name, title, and signature of your authorizing official (the name, title, and signature must match exactly the name, title, and signature in MMS qualification records); and
(9) A statement that you will adhere to the requirements of subpart I of this part.
(c) If you have submitted an application to relinquish a lease or grant, you will be billed for any outstanding payments that are due before the relinquishment takes effect, as provided in paragraph (a) of this section.
At an interval no more frequent than every 5 years, the MMS may review your lease or grant area to determine whether the lease or grant area is larger than needed to develop the project and manage activities in a manner that is consistent with the provisions of this part. The MMS will notify you of our proposal to contract the lease or grant area.
(a) The MMS will give you the opportunity to present orally or in writing information demonstrating that you need the area in question to manage lease or grant activities consistent with these regulations.
(b) Prior to taking action to contract the lease or grant area, MMS will issue a decision addressing your contentions that the area is needed.
(c) You may appeal this decision under § 285.118 of this part.
(a) The Secretary will cancel any lease or grant issued under this part upon proof that it was obtained by fraud or misrepresentation, and after notice and opportunity to be heard has been afforded to the lessee or grant holder.
(b) The Secretary may cancel any lease or grant issued under this part when:
(1) The Secretary determines after notice and opportunity for a hearing that, with respect to the lease or grant that would be canceled, the lessee or grantee has failed to comply with any applicable provision of the OCS Lands Act or these regulations; any order of the Director; or any term, condition or stipulation contained in the lease or grant, and that the failure to comply continued 30 days (or other period MMS specifies) after you receive notice from MMS. The Secretary will mail a notice by registered or certified letter to the lessee or grantee at its record post office address;
(2) The Secretary determines after notice and opportunity for a hearing that you have terminated commercial operations under your COP, as provided in § 285.635, or other approved activities under your GAP, as provided in § 285.656;
(3) Required by national security or defense; or
(4) The Secretary determines after notice and opportunity for a hearing that continued activity under the lease or grant:
(i) Would cause serious harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance; and
(ii) That the threat of harm or damage would 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 the lease or grant in force.
(a) For acquisition fees or the initial 6-months rent paid for the preliminary term of your lease, you must make credit card or automated clearing house payments through the
(b) For rent during the preliminary term, subsequent to the first 6-months rent, or the site assessment term; or operating fees during the operations term, you must make your payments as required in § 218.51 of this chapter.
(c) This table summarizes payments you must make for leases and grants, unless otherwise specified in the Final Sale Notice:
(a) For a competitive lease or grant that we offer through sealed bidding, you must submit a deposit of 20 percent of the total bid amount, unless some other amount is specified in the Final Sale Notice.
(b) For a competitive lease that we offer through ascending bidding, you must submit a deposit as established in the Final Sale Notice.
(c) You must pay any balances on accepted high bids in accordance with the Final Sale Notice, this part, and your lease or grant instrument.
(d) The deposit will be forfeited for any successful bidder who fails to execute the lease within the prescribed time, or otherwise does not comply with the regulations concerning acquisition of a lease or grant or stipulations in the Final Sale Notice.
When requesting a noncompetitive lease, you must meet the initial payment (acquisition fee) requirements of this section, unless specified otherwise in your lease instrument. No initial payment is required when requesting noncompetitive ROW grants and RUE grants.
(a) If you request a noncompetitive lease, you must submit an acquisition fee of $0.25 per acre, unless otherwise set by the Director, as provided in § 285.500.
(b) If MMS determines there is no competitive interest, we will then:
(1) Retain your acquisition fee if we issue you a lease; or
(2) Refund your acquisition fee, without interest, if we do not issue your requested lease.
(c) If we determine that there is a competitive interest in an area you requested, then we will proceed with a competitive lease sale process provided for in subpart B of this part, and we will:
(1) Apply your acquisition fee to the required deposit for your bid amount if you submit a bid;
(2) Apply your acquisition fee to your bonus bid if you acquire the lease; or
(3) Retain your acquisition fee if you do not bid for or acquire the lease.
(a) The rent for a commercial lease is $3 per acre per year, unless otherwise established in the Final Sale Notice or lease.
(1) You must pay the first 6-months rent, as provided in § 285.500, 45 days after we issue your lease.
(2) You must pay rent at the beginning of each subsequent 1-year period in accordance with the regulations at § 218.51 of this chapter for the entire lease area until the facility begins to generate commercially, as specified in § 285.506 or as otherwise specified in the Final Sale Notice or lease instrument:
(i) For leases issued competitively, the MMS will specify in the Final Sale Notice and lease any adjustment to the rent fee to take effect during the operations term and prior to the commercial generation.
(ii) For leases issued noncompetitively, the MMS will specify in the lease any adjustment to the rent fee to take effect during the operations term and prior to the commercial generation.
(3) You must pay the rent for a project easement in addition to the lease rent, as provided in § 285.507. You must commence rent payments for your project easement upon our approval of your COP or GAP.
(b) After your lease begins commercial generation of electricity or on the date specified by MMS, you must pay operating fees in the amount specified in § 285.506:
(1) For leases issued competitively, MMS will specify in the Final Sale Notice and lease the date when operating fees commence; and
(2) For leases issued noncompetitively, MMS will specify in the lease the date when operating fee commences.
If you develop your commercial lease in phases, as approved by us in your COP under § 285.629, you must pay:
(a) Rent on the portion of the lease that is not authorized for commercial operations.
(b) Operating fees on the portion of the lease that is authorized for commercial operations, in the amount specified in § 285.506 and as described in § 285.503(b).
(c) Rent for a project easement in addition to lease rent, as provided in § 285.507. You must commence rent payments for your project easement upon our approval of your COP.
(a) The rent for a limited lease is $3 per acre per year, unless otherwise established in the Final Sale Notice and your lease instrument.
(b) You must pay the first 6-months rent when MMS issues your limited lease, as provided in § 285.500.
(c) You must pay rent at the beginning of each subsequent 1-year period on the entire lease area for the duration of your operations term in accordance with the regulations at § 218.51 of this chapter.
(d) The MMS will not charge an operating fee for the authorized sale of power from a limited lease.
If you are generating electricity, you must pay operating fees on your commercial lease when you begin commercial generation, as described in § 285.503.
(a) The MMS will determine the annual operating fee for activities relating to the generation of electricity on your lease based on the following formula,
(1) F is the dollar amount of the annual operating fee;
(2) M is the nameplate capacity expressed in megawatts;
(3) H is the number of hours in a year, equal to 8,760, used to calculate an annual payment;
(4) c is the “capacity factor” representing the anticipated efficiency of the facility's operation expressed as a decimal between zero and one;
(5) P is a measure of the annual average wholesale electric power price expressed in dollars per megawatt hour, as provided in paragraph (c)(2) of this section; and
(6) r is the operating fee rate expressed as a decimal between zero and one.
(b) The annual operating fee formula relating to the value of annual electricity generation is restated as:
(c) The MMS will specify operating fee parameters in the Final Sale Notice for commercial leases issued competitively and in the lease for those issued noncompetitively.
(1) Unless MMS specifies otherwise, in the operating fee rate, (r) is 0.02 for each year the operating fee applies when you begin commercial generation of electricity. We may apply a different fee rate for new projects (
(2) The power price (P), for each year when the operating fee applies, will be determined annually. The process by which the power price will be determined will be specified in the Final Sale Notice and/or in the lease. The MMS:
(i) Will use the most recent annual average wholesale power price in the State in which a project's transmission cables make landfall, as published by the DOE, Energy Information Administration (EIA), or other publicly available wholesale power price indices; and
(ii) May adjust the published average wholesale power price to reflect documented variations by State or within a region and recent market conditions.
(3) The MMS will select the capacity factor (c) based upon applicable analogs drawn from present and future domestic and foreign projects that operate in comparable conditions and on comparable scales.
(i) Upon the completion of the first year of commercial operations on the lease, MMS may adjust the capacity factor as necessary (to accurately represent a comparison of actual production over a given period of time with the amount of power a facility would have produced if it had run at full capacity) in a subsequent year.
(ii) After the first adjustment, MMS may adjust the capacity factor (to accurately represent a comparison of actual generation over a given period of time with the amount of power a facility would have generated if it had run at full capacity) no earlier than in 5-year intervals from the most recent year that MMS adjusts the capacity factor.
(iii) The process by which MMS will adjust the capacity factor, including any calculations (incorporating an average capacity factor reflecting actual operating experience), will be specified in the lease. The operator or lessee may request review and adjustment of the capacity factor under § 285.510.
(4) Ten days after the anniversary date of when you began to commercially generate electricity, you must submit to MMS documentation of the gross annual generation of electricity produced by the generating facility on the lease. You must use the same information collection form as authorized by the EIA for this information.
(5) For the nameplate capacity (M), MMS will use the total installed capacity of the equipment you install, as specified in your approved COP.
(d) You must submit all operating fee payments to MMS in accordance with the provisions under § 218.51 of this chapter.
(e) The MMS will establish the operating fee in the Final Sale Notice or in the lease on a case-by-case basis for:
(1) Activities that do not relate to the generation of electricity (e.g., hydrogen production), and
(2) Leases issued for hydrokinetic activities requiring a FERC license.
(a) You must pay MMS a rent fee for your project easement of $5 per acre, subject to a minimum of $450 per year, unless specified otherwise in the Final Sale Notice or lease:
(1) The size of the project easement area for a cable or a pipeline is the full length of the corridor and a width of 200 feet (61 meters), centered on the cable or pipeline; and
(2) The size of a project easement area for an accessory platform is limited to the aerial extent of anchor chains and other facilities and devices associated with the accessory.
(b) You must commence rent payments for your project easement upon our approval of your COP or GAP:
(1) You must make the first rent payment when the operations term begins, as provided in § 285.500;
(2) You must submit all subsequent rent payments in accordance with the regulations at § 218.51 of this chapter; and
(3) You must continue to pay annual rent for your project easement until your lease is terminated.
(a) For each ROW grant MMS approves under subpart C of this part, you must pay an annual rent as follows, unless specified otherwise in the Final Sale Notice:
(1) A fee of $70 for each nautical mile or part of a nautical mile of the OCS that your ROW crosses; and
(2) An additional $5 per acre, subject to a minimum of $450 for use of the entire affected area, if you hold a ROW grant that includes a site outside the corridor of a 200-foot width (61 meters), centered on the cable or pipeline. The affected area includes the areal extent of anchor chains, risers, and other devices associated with a site outside the corridor.
(b) For each RUE grant MMS approves under subpart C of this part, you must pay a rent of:
(1) $5 per acre per year; or
(2) A minimum of $450 per year.
(c) You must make the rent payments required by paragraphs (a) and (b) of this section on:
(1) An annual basis;
(2) For a 5-year period; or
(3) For multiples of 5 years.
(d) You must make the first annual rent payment upon approval of your ROW grant or RUE grant request, as provided in § 285.500, and all subsequent rent payments to MMS in accordance with the regulations at § 218.51 of this chapter.
(a) For each lease, ROW grant, or RUE grant issued under this part, you must identify one person who is responsible for all payments due and payable under the provisions of the lease or grant. The responsible person identified is designated as the payor, and you must document acceptance of such responsibilities, as provided in § 218.52 of this chapter.
(b) All payors must submit payments and maintain auditable records in accordance with guidance we issue or any applicable regulations in subchapter A of this chapter. In addition, the lessee or grant holder must also maintain such auditable records.
(a) The MMS Director may reduce or waive the rent or operating fee or components of the operating fee, such as the fee rate or capacity factor, when the Director determines that it is necessary to encourage continued or additional activities.
(b) When requesting a reduction or waiver, you must submit an application to us that includes all of the following:
(1) The number of the lease, ROW grant, or RUE grant involved;
(2) Name of each lessee or grant holder of record;
(3) Name of each operator;
(4) A demonstration that:
(i) Continued activities would be uneconomic without the requested reduction or waiver, or
(ii) A reduction or waiver is necessary to encourage additional activities; and
(5) Any other information required by the Director.
(c) No more than 6 years of your operations term will be subject to a full waiver of the operating fee.
(a) Before MMS will issue your commercial lease or approve an assignment of an existing commercial lease, you (or, for an assignment, the proposed assignee) must guarantee compliance with all terms and conditions of the lease by providing either:
(1) A $100,000 minimum, lease-specific bond; or
(2) Another approved financial assurance instrument guaranteeing performance up to $100,000, as specified in §§ 285.526 through 285.529.
(b) You meet the financial assurance requirements under this subpart if your designated lease operator provides a $100,000 minimum, lease-specific bond or other approved financial assurance that guarantees compliance with all terms and conditions of the lease.
(1) The dollar amount of the minimum, lease-specific financial assurance in paragraphs (a)(1) and (b) of this section will be adjusted to reflect changes in the Consumer Price Index-All Urban Consumers (CPI-U) or a substantially equivalent index if the CPI-U is discontinued; and
(2) The first CPI-U-based adjustment can be made no earlier than the 5-year anniversary of the adoption of this rule. Subsequent CPI-U-based adjustments may be made every 5 years thereafter.
(a) The basic financial assurance requirements for each stage of your commercial lease are as follows:
(b) Each bond or other financial assurance must guarantee compliance with all terms and conditions of the lease. You may provide a new bond or increase the amount of your existing bond, to satisfy any additional financial assurance requirements.
(c) For hydrokinetic commercial leases, supplemental financial assurance may be required in an amount determined by MMS before FERC issues a license.
(a) The MMS will base the determination for the amounts of the SAP, COP, and decommissioning financial assurance requirements on estimates of the cost to meet all accrued lease obligations.
(b) We determine the amount of the supplemental and decommissioning financial assurance requirements on a case-by-case basis. The amount of the financial assurance must be no less than the amount required to meet all lease obligations, including:
(1) The projected amount of rent and other payments due the Government over the next 12 months;
(2) Any past due rent and other payments;
(3) Other monetary obligations; and
(4) The estimated cost of facility decommissioning, as required by subpart I of this part.
(c) If your cumulative potential obligations and liabilities increase or decrease, we may adjust the amount of supplemental or the decommissioning financial assurance.
(1) If we propose adjusting your financial assurance amount, we will notify you of the proposed adjustment and give you an opportunity to comment; and
(2) We may approve a reduced financial assurance amount if you request it and if the reduced amount that you request continues to be greater than the sum of:
(i) The projected amount of rent and other payments due the Government over the next 12 months;
(ii) Any past due rent and other payments;
(iii) Other monetary obligations; and
(iv) The estimated cost of facility decommissioning.
(a) Before MMS will issue your limited lease, ROW grant, or RUE grant, you or a proposed assignee must guarantee compliance with all terms and conditions of the lease or grant by providing either:
(1) A $300,000 minimum, lease- or grant-specific bond; or
(2) Another approved financial assurance instrument of such minimum level as specified in §§ 285.526 through 285.529.
(b) You meet the financial assurance requirements under this subpart if your designated lease or grant operator provides a minimum limited lease-specific or grant-specific bond in an amount sufficient to guarantee compliance with all terms and conditions of the limited lease or grant.
(1) The dollar amount of the minimum, lease- or grant-specific financial assurance in paragraph (a)(1) of this section will be adjusted to reflect changes in the CPI-U or a substantially equivalent index if the CPI-U is discontinued; and
(2) The first CPI-U-based adjustment can be made no earlier than the 5-year anniversary of the adoption of this rule. Subsequent CPI-U-based adjustments may be made every 5 years thereafter.
(a) The MMS may require you to increase the level of your financial assurance as activities progress on your limited lease or grant. We will base the determination for the amount of financial assurance requirements on our estimate of the cost to meet all accrued lease or grant obligations, including:
(1) The projected amount of rent and other payments due the Government over the next 12 months;
(2) Any past due rent and other payments;
(3) Other monetary obligations; and
(4) The estimated cost of facility decommissioning.
(b) You may satisfy the requirement for increased financial assurance levels for the limited lease or grant by increasing the amount of your existing bond or replacing your existing bond.
(c) The MMS will authorize you to establish a separate decommissioning bond or other financial assurance for your limited lease or grant.
(1) The separate decommissioning bond or other financial assurance instrument must meet the requirements specified in §§ 285.525 through 285.529.
(2) The MMS will allow you to provide your financial assurance for decommissioning in accordance with the number of facilities installed or being installed. The MMS must approve the schedule for providing the appropriate financial assurance coverage.
(a) Any bond or other acceptable financial assurance instrument that you provide must:
(1) Be payable to MMS upon demand; and
(2) Guarantee compliance of all lessees, grant holders, operators, and payors with all terms and conditions of the lease or grant, any subsequent approvals and authorizations, and all applicable regulations.
(b) All bonds and other forms of financial assurance must be on or in a form approved by MMS. You may submit this on an approved form that you have reproduced or generated by use of a computer. If the document you submit omits any terms and conditions that are included on the MMS-approved form, your bond is deemed to contain the omitted terms and conditions.
(c) Surety bonds must be issued by an approved surety listed in the current Treasury Circular 570, as required by 31 CFR 223.16. You may obtain a copy of
(d) Your surety bond cannot exceed the underwriting limit listed in the current Treasury Circular 570, except as permitted therein.
(e) You and a qualified surety must execute your bond. When the surety is a corporation, an authorized corporate officer must sign the bond and attest to it over the corporate seal.
(f) You may not terminate the period of liability of your bond or cancel your bond, except as provided in this subpart. Bonds must continue in full force and effect even though an event has occurred that could diminish or terminate a surety's obligation under State law.
(g) Your surety must notify you and MMS within 5 business days after:
(1) It initiates any judicial or administrative proceeding alleging its insolvency or bankruptcy; or
(2) The Treasury decertifies the surety.
(a) You may use other types of security instruments, if MMS determines that such security protects MMS to the same extent as the surety bond. The MMS will consider pledges of the following:
(1) U.S. Department of Treasury securities identified in 31 CFR part 225;
(2) Cash in an amount equal to the required dollar amount of the financial assurance, to be deposited and maintained in a Federal depository account of the U.S. Treasury by MMS;
(3) Certificates of deposit or savings accounts in a bank or financial institution organized or authorized to transact business in the United States with:
(i) Minimum net assets of $500,000,000; and
(ii) Minimum Bankrate.com Safe & Sound rating of 3 Stars, and Capitalization, Assets, Equity and Liquidity (CAEL) rating of 3 or less;
(4) Negotiable U.S. Government, State, and municipal securities or bonds having a market value of not less than the required dollar amount of the financial assurance and maintained in a Securities Investors Protection Corporation insured trust account by a licensed securities brokerage firm for the benefit of the MMS;
(5) Investment-grade rated securities having a Standard and Poor's rating of AAA or an equivalent rating from a nationally recognized securities rating service having a market value of not less than the required dollar amount of the financial assurance and maintained in a Securities Investors Protection Corporation insured trust account by a licensed securities brokerage firm for the benefit of MMS; and
(6) Insurance, if its form and function is such that the funding or enforceable pledges of funding are used to guarantee performance of regulatory obligations in the event of default on such obligations by the lessee. Insurance must have an A.M. Best rating of “superior” or an equivalent rating from a nationally recognized insurance rating service.
(b) If you use a Treasury security:
(1) You must post 115 percent of your financial assurance amount;
(2) You must monitor the collateral value of your security. If the collateral value of your security as determined in accordance with the 31 CFR part 203 Collateral Margins Table (which can be found at
(3) You must include with your pledge authority for us to sell the security and use the proceeds if we determine that you have failed to comply with any of the terms and conditions of your lease or grant, any subsequent approval or authorization, or applicable regulations.
(c) If you use the instruments described in paragraphs (a)(4) or (a)(5) of this section, you must provide MMS by the end of each calendar year a certified statement describing the nature and market value of the instruments maintained in that account, and including any current statements or reports furnished by the brokerage firm to the lessee concerning the asset value of the account.
The MMS may allow you to use your financial strength and reliability to meet financial assurance requirements. We will make this determination based on audited financial statements, business stability, reliability, and compliance with regulations.
(a) You must provide the following information if you want to demonstrate financial strength and reliability to meet your financial assurance requirements:
(1) Audited financial statements (including auditor's certificate, balance sheet, and profit and loss sheet) that show you have financial capacity substantially in excess of existing and anticipated lease and other obligations;
(2) Evidence that shows business stability based on 5 years of continuous operation and generation of renewable energy on the OCS or onshore;
(3) Evidence that shows reliability in meeting obligations based on credit ratings or trade references, including names and addresses of other lessees, contractors, and suppliers with whom you have dealt; and
(4) Evidence that shows a record of compliance with laws, regulations, and lease, ROW, or RUE terms.
(b) If we approve your request to use your financial strength and reliability to meet your financial assurance requirements, you must submit annual updates to the information required by paragraph (a) of this section. You must submit this information no later than March 31 of each year.
(c) If the annual updates to the information required by paragraph (a) of this section do not continue to demonstrate financial strength and reliability or MMS has reason to believe that you are unable to meet the financial assurance requirements of this section, after notice and opportunity for a hearing, MMS will terminate your ability to use financial strength and reliability for financial assurance and require you to provide another type of financial assurance. You must provide this new financial assurance instrument within 90 days after we terminate your use of financial strength and reliability.
(a) You may use a third-party guaranty if the guarantor meets the criteria prescribed in paragraph (b) of this section and submits an agreement meeting the criteria prescribed in paragraph (c) of this section. The agreement must guarantee compliance with the obligations of all lessees and operators and grant holders.
(b) The MMS will consider the following factors in deciding whether to accept an agreement:
(1) The length of time that your guarantor has been in continuous operation as a business entity. You may exclude periods of interruption that are beyond the guarantor's control by demonstrating, to the satisfaction of the Director, that the interruptions do not affect the likelihood of your guarantor remaining in business during the SAP, COP, and decommissioning stages of activities covered by the indemnity agreement.
(2) Financial information available in the public record or submitted by your guarantor in sufficient detail to show us that your guarantor meets the criterion stated in paragraph (b)(4) of this section. Such detail includes:
(i) The current rating for your guarantor's most recent bond issuance by a generally recognized bond rating service such as Moody's Investor Service or Standard and Poor's Corporation;
(ii) Your guarantor's net worth, taking into account liabilities for compliance with all terms and conditions of your lease, regulations, and other guarantees;
(iii) Your guarantor's ratio of current assets to current liabilities, taking into account liabilities for compliance with all terms and conditions of your lease, regulations, and other guarantees; and
(iv) Your guarantor's unencumbered domestic fixed assets.
(3) If the information in paragraph (b)(2) of this section is not publicly available, your guarantor must submit the information in the following table,
(4) Your guarantor's total outstanding and proposed guarantees must not exceed 25 percent of its unencumbered domestic net worth.
(c) Your guarantor must submit an agreement executed by the guarantor and all parties bound by the agreement. All parties are bound jointly and severally and must meet the qualifications set forth in § 285.107.
(1) When any party is a corporation, two corporate officers authorized to execute the guaranty agreement on behalf of the corporation must sign the agreement.
(2) When any party is a partnership, joint venture, or syndicate, the guaranty agreement must bind each party who has a beneficial interest in your guarantor and provide that, upon MMS demand under your guaranty, each party is jointly and severally liable for compliance with all terms and conditions of your lease(s) or grant(s) covered by the agreement.
(3) When forfeiture of the guaranty is called for, the agreement must provide that your guarantor will either bring your lease(s) or grant(s) into compliance or provide, within 7 days, sufficient funds to permit MMS to complete corrective action.
(4) The guaranty agreement must contain a confession of judgment, providing that, if we determine that you are, or your operator or operating rights owner is, in default, the guarantor must not challenge the determination and must remedy the default.
(5) If you fail, or your operator or operating rights owner fails, to comply with any law, term, or regulation, your guarantor must either take corrective action or provide, within 7 days or other agreed upon time period, sufficient funds for MMS to complete corrective action. Such compliance must not reduce your guarantor's liability.
(6) If your guarantor wants to terminate the period of liability, your guarantor must notify you and us at least 90 days before the proposed termination date, obtain our approval for termination of all or a specified portion of the guarantee for liabilities arising after that date, and remain liable for all your work performed during the period the agreement is in effect.
(7) Each guaranty submitted pursuant to this section is deemed to contain all the above terms, even if they are not actually in the agreement.
(d) Before the termination of your guaranty, you must provide an acceptable replacement in the form of a bond or other security.
(a) In lieu of a surety bond, MMS may authorize you to establish a lease-, ROW grant-, or RUE grant-specific decommissioning account in a federally-insured institution. The funds may not be withdrawn from the account without our written approval.
(1) The funds must be payable to MMS and pledged to meet your lease or
(2) You must fully fund the account within the time MMS prescribes to cover all costs of decommissioning including site clearance. The MMS will estimate the cost of decommissioning, including site clearance.
(b) Any interest paid on the account will be treated as account funds unless we authorize in writing that any interest be paid to the depositor.
(c) We may allow you to pledge Treasury securities, payable to MMS on demand, to satisfy your obligation to make payments into the account. Acceptable Treasury securities and their collateral value are determined in accordance with 31 CFR part 203, Collateral Margins Table (which can be found at
(d) We may require you to commit a specified stream of revenues as payment into the account so that the account will be fully funded, as prescribed in paragraph (a)(2) of this section. The commitment may include revenue from other operations.
(a) If your surety is decertified by the Treasury, becomes bankrupt or insolvent, or if your surety's charter or license is suspended or revoked, or if any other approved financial assurance expires for any reason, you must:
(1) Inform MMS within 3 business days about the financial assurance lapse; and
(2) Provide new financial assurance in the amount set by MMS, as provided in this subpart.
(b) You must notify MMS within 3 business days after you learn of any action filed alleging that you, your surety, or third-party guarantor, is insolvent or bankrupt.
If the value of your financial assurance is reduced below the required financial assurance amount because of a default or any other reason, you must provide additional financial assurance sufficient to meet the requirements of this subpart within 45 days or within a different period as specified by MMS.
(a) Terminating the period of liability of a bond ends the period during which surety liability continues to accrue. The surety continues to be responsible for obligations and liabilities that accrued during the period of liability and before the date on which MMS terminates the period of liability under paragraph (b) of this section. The liabilities that accrue during a period of liability include:
(1) Obligations that started to accrue before the beginning of the period of liability and have not been met; and
(2) Obligations that began accruing during the period of liability.
(b) Your surety must submit to MMS its request to terminate the period of liability under its bond and notify you of that request. If you intend to continue activities, or have not met all obligations of your lease or grant, you must provide a replacement bond or alternative form of financial assurance of equivalent or greater value. The MMS will terminate that period of liability within 90 days after MMS receives the request.
(a) The MMS will release a bond or allow a surety to cancel a bond, and will relieve the surety from accrued obligations only if:
(1) The MMS determines that there are no outstanding obligations covered by the bond; or
(2) The following occurs:
(i) The MMS accepts a replacement bond or an alternative form of financial assurance in an amount equal to or greater than the bond to be cancelled to cover the terminated period of liability;
(ii) The surety issuing the new bond has expressly agreed to assume all outstanding liabilities under the original bond that accrued during the period of liability that was terminated; and
(iii) The surety issuing the new bond has agreed to assume that portion of the outstanding liabilities that accrued
(b) When your lease or grant ends, your surety(ies) remain(s) responsible, and MMS will retain any financial assurance as follows:
(1) The period of liability ends when you cease all operations and activities under the lease or grant, including decommissioning and site clearance;
(2) Your surety or collateral financial assurance will not be released until 7 years after the lease ends, or a longer period as necessary to complete any appeals or judicial litigation related to your bonded obligation, or for MMS to determine that all of your obligations under the lease or grant have been satisfied; and
(3) The MMS will reduce the amount of your bond or return a portion of your financial assurance if we determine that we need less than the full amount of the bond or financial assurance to meet any possible future obligations.
When your lease or grant ends, your surety(ies) remain(s) responsible, and MMS will retain any pledged security as shown in the following table:
(a) The MMS may call for forfeiture of all or part of the bond, pledged security, or other form of guaranty if:
(1) After notice and demand for performance by MMS, you refuse or fail, within the timeframe we prescribe, to comply with any term or condition of your lease or grant, other authorization or approval, or applicable regulations; or
(2) You default on one of the conditions under which we accepted your bond.
(b) We may pursue forfeiture without first making demands for performance against any co-lessee or holder of an interest in your ROW or RUE, or other person approved to perform obligations under your lease or grant.
(a) The MMS will notify you and your surety, including any provider of financial assurance, in writing of the call for forfeiture and provide the reasons for the forfeiture and the amount to be forfeited. We will base the amount upon an estimate of the total cost of corrective action to bring your lease or grant into compliance.
(b) We will advise you and your surety that you may avoid forfeiture if, within 10 business days:
(1) You agree to and demonstrate in writing to MMS that you will bring your lease or grant into compliance within the timeframe we prescribe, and you do so; or
(2) Your surety agrees to and demonstrates that it will bring your lease or grant into compliance within the timeframe we prescribe, even if the cost of compliance exceeds the face amount of the bond.
(a) If MMS determines that your bond or other security is forfeited, we will collect the forfeited amount and use the funds to bring your lease or grant(s) into compliance and correct any default.
(b) If the amount collected under your bond or other security is insufficient to pay the full cost of corrective action, MMS may take or direct action to obtain full compliance and recover all costs in excess of the forfeited bond from you or any co-lessee or co-grantee.
(c) If the amount collected under your bond or other security exceeds the full cost of corrective action to bring your lease or grant(s) into compliance, we will return the excess funds to the party from whom the excess was collected.
(a) The MMS will distribute among the eligible coastal States 27 percent of the following revenues derived from qualified projects, where a qualified project and qualified project area is determined in § 285.541 and an eligible State is determined in § 285.542, with each term defined in § 285.112. Revenues subject to distribution to eligible States include all bonuses, acquisition fees, rentals, and operating fees derived from the entire qualified project area and associated project easements not limited to revenues attributable to the portion of the project area within 3 miles of the seaward boundary of a coastal State. The revenues to be shared do not include administrative fees such as service fees and those assessed for civil penalties and forfeiture of bond or other surety obligations.
(b) The project area is the area included within a single lease or grant. For each qualified project, MMS will determine and announce the project area and its geographic center at the time it grants or issues a lease, easement, or right-of-way on the OCS. If a qualified project lease or grant's boundaries change significantly due to actions pursuant to §§ 285.435 or 285.436, MMS will re-evaluate the project area to determine whether the geographic center has changed. If it has, MMS will re-determine State eligibility and shares accordingly.
(c) To determine each eligible State's share of the 27 percent of the revenues for a qualified project, MMS will use the inverse distance formula, which apportions shares according to the relative proximity of the nearest point on the coastline of each eligible State to the geographic center of the qualified project area. If S
A qualified project for the purpose of revenue sharing with eligible coastal States is one authorized under subsection 8(p) of the OCS Lands Act, which includes acreage within the area extending 3 nautical miles seaward of State submerged lands. A qualified project is subject to revenue sharing with those States that are eligible for revenue sharing under § 285.542. The entire area within a lease or grant for the qualified project, excluding project easements, is considered the qualified project area.
A State is eligible for payment of revenues if any part of the State's coastline is located within 15 miles of the announced geographic center of the project area of a qualified project. A State is not eligible for revenue sharing if all parts of that State's coastline are more than 15 miles from the announced geographic center of the qualified project area. This is the case even if the qualified project area is located wholly or partially within an area extending 3 nautical miles seaward of the submerged lands of that State or if there are no States with a coastline less than 15 miles from the announced geographic center of the qualified project area.
(a) Assume that the geographic center of the project area lies 12 miles from the closest coastline point of State A and 4 miles from the closest coastline point of State B. The MMS will round dollar shares to the nearest whole dollar. The proportional share due each State would be calculated as follows:
(1) State A's share = [(
(2) State B's share = [
(b) Therefore, State B would receive a share of revenues that is three times as large as that awarded to State A, based on the finding that State B's nearest coastline is one-third the distance to the geographic center of the qualified project area as compared to State A's nearest coastline. Eligible States share the 27 percent of the total revenues from the qualified project as mandated under the OCS Lands Act. Hence, if the qualified project generates $1,000,000 of Federal revenues in a given year, the Federal Government would distribute the States' 27-percent share as follows:
(1) State A's share = $270,000 ×
(2) State B's share = $270,000 ×
You must submit a SAP, COP, or GAP and receive MMS approval as set forth in the following table:
Your plan submission requirements depend on whether your lease or grant was issued competitively or noncompetitively under subpart B or subpart C of this part.
(a) If your lease or grant is issued competitively, you must submit your SAP or your GAP within 6 months of issuance.
(b) If you request that a lease or grant be issued noncompetitively, you must submit your SAP or your GAP within 60 days after the Director issues a determination that there is no competitive interest.
(c) If you intend to continue your commercial lease with an operations term, you must submit a COP, or a FERC license application, at least 6 months before the end of your site assessment term.
(d) You may submit your COP or FERC license application with your SAP.
(1) You must provide sufficient data and information with your COP for MMS to complete the needed reviews and NEPA analysis; and
(2) The MMS may need to conduct additional reviews, including NEPA analysis, if significant new information becomes available after you complete your site assessment activities or you revise your COP. As a result of the additional reviews, we may require modification of your COP.
Until MMS releases your financial assurance under § 285.534, you must maintain and provide to MMS, upon request, all data and information related to compliance with required terms and conditions of your SAP, COP, or GAP.
(a) A SAP describes the activities (e.g., installation of meteorological towers, meteorological buoys) you plan to perform for the characterization of your commercial lease, including your project easement, or to test technology devices.
(1) Your SAP must describe how you will conduct your resource assessment (e.g., meteorological and oceanographic data collection) or technology testing activities; and
(2) The MMS will withhold trade secrets and commercial or financial information that is privileged or confidential from public disclosure under exemption 4 of the FOIA and as provided in § 285.113.
(b) Your SAP must include data from:
(1) Physical characterization surveys (e.g., geological and geophysical surveys or hazards surveys); and
(2) Baseline environmental surveys (e.g., biological or archaeological surveys).
(c) You must receive MMS approval of your SAP before you can begin any of the approved activities on your lease, as provided in § 285.613.
(d) If you propose to construct a facility or combination of facilities deemed by MMS to be complex or significant, as provided in § 285.613(a)(1), you must also comply with the requirements of subpart G of this part and submit your Safety Management System as required by § 285.810.
(a) Your SAP must demonstrate that you have planned and are prepared to conduct the proposed site assessment activities in a manner that conforms to your responsibilities listed in § 285.105(a) and:
(1) Conforms to all applicable laws, regulations, and lease provisions of your commercial lease;
(2) Is safe;
(3) Does not unreasonably interfere with other uses of the OCS, including those involved with national security or defense;
(4) Does not cause undue harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance;
(5) Uses best available and safest technology;
(6) Uses best management practices; and
(7) Uses properly trained personnel.
(b) You must also demonstrate that your site assessment activities will collect the necessary information and data required for your COP, as provided in § 285.626(a).
You must submit one paper copy and one electronic version of your SAP to MMS at the address listed in § 285.110(a).
Your SAP must include the following information, as applicable.
(a) For all activities you propose to conduct under your SAP, you must provide the following information:
(b) You must provide the results of geophysical and geological surveys, hazards surveys, archaeological surveys (if required), and baseline collection studies (e.g., biological) with the supporting data in your SAP:
(c) If you submit your COP or FERC license application with your SAP then:
(1) You must provide sufficient data and information with your COP or FERC license application for MMS and/or FERC to complete the needed reviews and NEPA analysis.
(2) You may need to revise your COP or FERC license application and MMS
(a) You must submit with your SAP detailed information to assist MMS in complying with NEPA and other relevant laws, as appropriate. For a noncompetitive commercial lease, you must submit a SAP that describes those resources, conditions, and activities listed in the following table that could be affected by your proposed activities, or that could affect the activities proposed in your SAP.
(b) For competitively issued commercial leases, MMS will have prepared a NEPA document and consistency determination for the lease sale and site assessment activities. However, if you submit a SAP that shows changes in impacts from those identified in the NEPA document or consistency determination prepared for the lease, MMS may determine that your SAP is subject to a new NEPA/CZMA and other relevant Federal reviews. In that case, MMS will notify you of the determination, and you must submit a SAP that describes those resources, conditions, and activities listed in the following table that could be affected by your proposed activities, or that could affect the activities proposed in your SAP, including:
Your SAP will be processed based on how your commercial lease was issued:
(a) The MMS will review your submitted SAP, and additional information provided pursuant to § 285.611, to determine if it contains the information necessary to conduct our technical and environmental reviews.
(1) We will notify you if we deem your proposed facility or combination of facilities to be complex or significant;
(2) We will notify you if your submitted SAP lacks any necessary information;
(b) The MMS will prepare NEPA analysis, as appropriate.
(c) As appropriate, we will coordinate and consult with relevant Federal and State agencies, executives of relevant local governments, and affected Indian tribes and will provide to other Federal, State, and local agencies and affected Indian tribes relevant nonproprietary data and information pertaining to your proposed activities.
(d) During the review process, we may request additional information if we determine that the information provided is not sufficient to complete the review and approval process. If you fail to provide the requested information, MMS may disapprove your SAP.
(e) Upon completion of our technical and environmental reviews and other reviews required by Federal laws (e.g., CZMA), MMS may approve, disapprove, or approve with modifications your SAP.
(1) If we approve your SAP, we will specify terms and conditions to be incorporated into your SAP. You must certify compliance with those terms and conditions required under § 285.615(c); and
(2) If we disapprove your SAP, we will inform you of the reasons and allow you an opportunity to submit a revised plan making the necessary corrections, and may suspend the term of your lease, as appropriate, to allow this to occur.
(a) You may begin conducting the activities approved in your SAP following MMS approval of your SAP.
(b) If you are installing a facility or a combination of facilities deemed by MMS to be complex or significant, as provided in § 285.613(a)(1), you must comply with the requirements of subpart G of this part and submit your Safety Management System required by § 285.810 before construction may begin.
(a) You must notify MMS in writing within 30 days of completing installation activities approved in your SAP.
(b) You must prepare and submit to MMS a report annually on November 1 of each year that summarizes your site assessment activities and the results of those activities. The MMS will withhold trade secrets and commercial or financial information that is privileged or confidential from public disclosure under exemption 4 of the FOIA and as provided in § 285.113.
(c) You must submit a certification of compliance annually (or other frequency as determined by MMS) with certain terms and conditions of your SAP that MMS identifies under § 285.613(e)(1). Together with your certification, you must submit:
(1) Summary reports that show compliance with the terms and conditions which require certification; and
(2) A statement identifying and describing any mitigation measures and monitoring methods and their effectiveness. If you identified measures that were not effective, you must include your recommendations for new mitigation measures or monitoring methods.
(a) You must notify MMS in writing before conducting any activities not described in your approved SAP, describing in detail the type of activities you propose to conduct. We will determine whether the activities you propose are authorized by your existing SAP or require a revision to your SAP. We may request additional information from you, if necessary, to make this determination.
(b) The MMS will periodically review the activities conducted under an approved SAP. The frequency and extent of the review will be based on the significance of any changes in available information and on onshore or offshore conditions affecting, or affected by, the activities conducted under your SAP. If the review indicates that the SAP should be revised to meet the requirements of this part, we will require you to submit the needed revisions.
(c) Activities for which a proposed revision to your SAP will likely be necessary include:
(1) Activities not described in your approved SAP;
(2) Modifications to the size or type of facility or equipment you will use;
(3) Changes in the surface location of a facility or structure;
(4) Addition of a facility or structure not contemplated in your approved SAP;
(5) Changes in the location of your onshore support base from one State to another, or to a new base requiring expansion;
(6) Changes in the location of bottom disturbances (anchors, chains, etc.) by 500 feet (152 meters) or greater from the approved locations. If a specific anchor pattern was approved as a mitigation measure to avoid contact with bottom features, any change in the proposed bottom disturbances would likely trigger the need for a revision;
(7) Structural failure of one or more facilities; or
(8) Changes to any other activity specified by MMS.
(d) We may begin the appropriate NEPA analysis and other relevant consultations when we determine that a proposed revision could:
(1) Result in a significant change in the impacts previously identified and evaluated;
(2) Require any additional Federal authorizations; or
(3) Involve activities not previously identified and evaluated.
(e) When you propose a revision, we may approve the revision if we determine that the revision is:
(1) Designed not to cause undue harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance; and
(2) Otherwise consistent with the provisions of subsection 8(p) of the OCS Lands Act.
(a) If, prior to the expiration of your site assessment term, you timely submit a COP meeting the requirements of this subpart, or a complete FERC license application, that describes the
(b) You are not required to initiate the decommissioning process for facilities that are authorized to remain in place under your approved COP or approved FERC license.
(c) If, following the technical and environmental review of your submitted COP, MMS determines that such facilities may not remain in place, you must initiate the decommissioning process, as provided in subpart I of this part.
(d) If FERC determines that such facilities may not remain in place, you must initiate the decommissioning process as provided in subpart I of this part.
(e) You must initiate the decommissioning process, as set forth in subpart I of this part, upon the termination of your lease.
The COP describes your construction, operations, and conceptual decommissioning plans under your commercial lease, including your project easement. The MMS will withhold trade secrets and commercial or financial information that is privileged or confidential from public disclosure under exemption 4 of the FOIA and in accordance with the terms of § 285.113.
(a) Your COP must describe all planned facilities that you will construct and use for your project, including onshore and support facilities and all anticipated project easements.
(b) Your COP must describe all proposed activities including your proposed construction activities, commercial operations, and conceptual decommissioning plans for all planned facilities, including onshore and support facilities.
(c) You must receive MMS approval of your COP before you can begin any of the approved activities on your lease.
Your COP must demonstrate that you have planned and are prepared to conduct the proposed activities in a manner that conforms to your responsibilities listed in § 285.105(a) and:
(a) Conforms to all applicable laws, implementing regulations, lease provisions, and stipulations or conditions of your commercial lease;
(b) Is safe;
(c) Does not unreasonably interfere with other uses of the OCS, including those involved with National security or defense;
(d) Does not cause undue harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance;
(e) Uses best available and safest technology;
(f) Uses best management practices; and
(g) Uses properly trained personnel.
(a) You must submit one paper copy and one electronic version of your COP to MMS at the address listed in § 285.110(a).
(b) You may submit information and a request for any project easement as part of your original COP submission or as a revision to your COP.
(a) You must submit the results of the following surveys for the proposed site(s) of your facility(ies). Your COP must include the following information:
(b) Your COP must include the following project-specific information, as applicable.
(a) You must submit with your COP detailed information to assist MMS in complying with NEPA and other relevant laws. Your COP must describe those resources, conditions, and activities listed in the following table that could be affected by your proposed activities, or that could affect the activities proposed in your COP, including:
(b) You must submit one paper copy and one electronic copy of your consistency certification. Your consistency certification must include:
(1) One copy of your consistency certification under subsection 307(c)(3)(B) of the CZMA (16 U.S.C. 1456(c)(3)(B)) and 15 CFR 930.76 stating that the proposed activities described in detail in your plans comply with the State(s) approved coastal management program(s) and will be conducted in a manner that is consistent with such program(s); and
(2) “Information,” as required by 15 CFR 930.76(a) and 15 CFR 930.58(a)(2), and “Analysis,” as required by 15 CFR 930.58(a)(3).
(c) You must submit your oil spill response plan, as required by part 254 of this subchapter.
(d) You must submit your Safety Management System as required by § 285.810.
(a) The MMS will review your submitted COP, and the information provided pursuant to § 285.627, to determine if it contains all the required information necessary to conduct our technical and environmental reviews. We will notify you if your submitted COP lacks any necessary information.
(b) The MMS will prepare an appropriate NEPA analysis.
(c) The MMS will forward one copy of your COP, consistency certification, and associated data and information under the CZMA to the State's CZM agency after all information requirements for the COP are met.
(d) As appropriate, MMS will coordinate and consult with relevant Federal, State, and local agencies and affected Indian tribes, and provide to them relevant nonproprietary data and information pertaining to your proposed activities.
(e) During the review process, we may request additional information if we determine that the information provided is not sufficient to complete the review and approval process. If you fail to provide the requested information, MMS may disapprove your COP.
(f) Upon completion of our technical and environmental reviews and other reviews required by Federal law (e.g., CZMA), MMS may approve, disapprove, or approve with modifications your COP.
(1) If we approve your COP, we will specify terms and conditions to be incorporated into your COP. You must certify compliance with certain of those terms and conditions, as required under § 285.633(b); and
(2) If we disapprove your COP, we will inform you of the reasons and allow you an opportunity to resubmit a revised plan addressing the concerns identified, and may suspend the term of your lease, as appropriate, to allow this to occur.
(g) If MMS approves your project easement, MMS will issue an addendum to your lease specifying the terms of the project easement. A project easement may include off-lease areas that:
(1) Contain the sites on which cable, pipeline, or associated facilities are located;
(2) Do not exceed 200 feet (61 meters) in width, unless safety and environmental factors during construction and maintenance of the associated cables or pipelines require a greater width; and
(3) For associated facilities, are limited to the area reasonably necessary for power or pumping stations or other accessory facilities.
In your COP, you may request development of your commercial lease in phases. In support of your request, you must provide details as to what portions of the lease will be initially developed for commercial operations and what portions of the lease will be reserved for subsequent phased development.
After your COP is approved, you must commence construction by the date given in the construction schedule required by § 285.626(b)(21), and included as a part of your approved COP, unless MMS approves a deviation from your schedule.
(a) You must submit to MMS the documents listed in the following table:
(b) You must submit your Safety Management System, as required by § 285.810 of this part.
(c) These activities must fall within the scope of your approved COP. If they do not fall within the scope of your approved COP, you will be required to submit a revision to your COP, under § 285.634, for MMS approval before commencing the activity.
(a) Based on MMS's environmental and technical reviews, we will specify terms and conditions to be incorporated into your COP.
(b) You must submit a certification of compliance annually (or other frequency as determined by MMS) with certain terms and conditions of your COP that MMS identifies. Together with your certification, you must submit:
(1) Summary reports that show compliance with the terms and conditions which require certification; and
(2) A statement identifying and describing any mitigation measures and monitoring methods, and their effectiveness. If you identified measures that were not effective, then you must make recommendations for new mitigation measures or monitoring methods.
(c) As provided at § 285.105(i), MMS may require you to submit any supporting data and information.
(a) You must notify MMS in writing before conducting any activities not described in your approved COP, describing in detail the type of activities you propose to conduct. We will determine whether the activities you propose are authorized by your existing COP or require a revision to your COP. We may request additional information from you, if necessary, to make this determination.
(b) The MMS will periodically review the activities conducted under an approved COP. The frequency and extent of the review will be based on the significance of any changes in available information, and on onshore or offshore conditions affecting, or affected by, the activities conducted under your COP. If the review indicates that the COP should be revised to meet the requirement of this part, we will require you to submit the needed revisions.
(c) Activities for which a proposed revision to your COP will likely be necessary include:
(1) Activities not described in your approved COP;
(2) Modifications to the size or type of facility or equipment you will use;
(3) Change in the surface location of a facility or structure;
(4) Addition of a facility or structure not described in your approved COP;
(5) Change in the location of your onshore support base from one State to another or to a new base requiring expansion;
(6) Changes in the location of bottom disturbances (anchors, chains, etc.) by 500 feet (152 meters) or greater from the approved locations (e.g., if a specific anchor pattern was approved as a mitigation measure to avoid contact with bottom features, any change in the proposed bottom disturbances would likely trigger the need for a revision);
(7) Structural failure of one or more facilities; or
(8) Change in any other activity specified by MMS.
(d) We may begin the appropriate NEPA analysis and relevant consultations when we determine that a proposed revision could:
(1) Result in a significant change in the impacts previously identified and evaluated;
(2) Require any additional Federal authorizations; or
(3) Involve activities not previously identified and evaluated.
(e) When you propose a revision, we may approve the revision if we determine that the revision is:
(1) Designed not to cause undue harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance; and
(2) Otherwise consistent with the provisions of subsection 8(p) of the OCS Lands Act.
You must notify the MMS, within 5 business days, any time you cease commercial operations, without an approved suspension, under your approved COP. If you cease commercial operations for an indefinite period which extends longer than 6 months, we may cancel your lease under
You must notify MMS in writing of the following events, within the time periods provided:
(a) No later than 30 days after commencing activities associated with the placement of facilities on the lease area under a Fabrication and Installation Report.
(b) No later than 30 days after completion of construction and installation activities under a Fabrication and Installation Report.
(c) At least 7 days before commencing commercial operations.
If you are conducting activities on your lease that:
(a) Do not require a FERC license (
(b) Require a FERC license or exemption, then you may commence commercial operations when permitted by the terms of your license or exemption.
(a) Upon completion of your approved activities under your COP, you must initiate the decommissioning process as set forth in subpart I of this part. You must submit your decommissioning application as provided in §§ 285.905 and 285.906.
(b) Upon completion of your approved activities under your FERC license, the terms of your FERC license will govern your decommissioning activities.
(a) A GAP describes your proposed construction, activities, and conceptual decommissioning plans for all planned facilities, including testing of technology devices and onshore and support facilities that you will construct and use for your project, including any project easements for the assessment and development of your limited lease or grant.
(b) You must receive MMS approval of your GAP before you can begin any of the approved activities on your lease or grant. For a ROW grant or RUE grant issued competitively, you must submit your GAP within 6 months of issuance.
Your GAP must demonstrate that you have planned and are prepared to conduct the proposed activities in a manner that:
(a) Conforms to all applicable laws, implementing regulations, lease provisions and stipulations;
(b) Is safe;
(c) Does not unreasonably interfere with other uses of the OCS, including those involved with national security or defense;
(d) Does not cause undue harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance;
(e) Uses best available and safest technology;
(f) Uses best management practices; and
(g) Uses properly trained personnel.
(a) You must submit one paper copy and one electronic version of your GAP to MMS at the address listed in § 285.110(a).
(b) If you have a limited lease, you may submit information on any project easement as part of your original GAP submission or as a revision to your GAP.
(a) You must provide the following results of geophysical and geological surveys, hazards surveys, archaeological surveys (if required), and baseline collection studies (e.g., biological) with the supporting data in your GAP:
(b) For all activities you propose to conduct under your GAP, you must provide the following information:
(c) If you are applying for a project easement or constructing a facility, or a combination of facilities deemed by MMS to be complex or significant, you must provide the following information in addition to what is required in paragraphs (a) and (b) of this section and comply with the requirements of subpart G of this part:
(d) The MMS will withhold trade secrets and commercial or financial information that is privileged or confidential from public disclosure in accordance with the terms of § 285.113.
You must submit with your GAP detailed information to assist MMS in complying with NEPA and other relevant laws. Your GAP must describe those resources, conditions, and activities listed in the following table that could be affected by your proposed activities, or that could affect the activities proposed in your GAP, including:
Your GAP will be processed based on how your limited lease, ROW grant, or RUE grant was issued:
(a) The MMS will review your submitted GAP, along with the information and certifications provided pursuant to § 285.646, to determine if it contains all the required information necessary to conduct our technical and environmental reviews.
(1) We will notify you if we deem your proposed facility or combination of facilities to be complex or significant; and
(2) We will notify you if your submitted GAP lacks any necessary information.
(b) The MMS will prepare appropriate NEPA analysis.
(c) When appropriate, we will coordinate and consult with relevant State and Federal agencies and affected Indian tribes and provide to other local, State, and Federal agencies and affected Indian tribes relevant nonproprietary data and information pertaining to your proposed activities.
(d) During the review process, we may request additional information if we determine that the information provided is not sufficient to complete the review and approval process. If you fail to provide the requested information, MMS may disapprove your GAP.
(e) Upon completion of our technical and environmental reviews and other reviews required by Federal law (e.g., CZMA), MMS may approve, disapprove, or approve with modifications your GAP.
(1) If we approve your GAP, we will specify terms and conditions to be incorporated into your GAP. You must certify compliance with certain of those terms and conditions, as required under § 285.653(c); and
(2) If we disapprove your GAP, we will inform you of the reasons and allow you an opportunity to resubmit a revised plan making the necessary corrections, and may suspend the term of your lease or grant, as appropriate, to allow this to occur.
After MMS approves your GAP, you may begin conducting the approved activities that do not involve a project easement or the construction of facilities on the OCS that MMS has deemed to be complex or significant.
If you are applying for a project easement, or installing a facility or a combination of facilities on your limited lease deemed by MMS to be complex or significant, as provided in § 285.648(a)(1), you also must comply with the requirements of subpart G of this part and submit your Safety Management System required by § 285.810 before construction may begin.
After MMS approves your GAP, you have:
(a) For a limited lease, 5 years to conduct your approved activities, unless we renew the term under §§ 285.425 through 285.429.
(b) For a ROW grant or RUE grant, the time provided in the terms of the grant.
(a) You must notify MMS in writing within 30 days after completing installation activities approved in your GAP.
(b) You must prepare and submit to MMS annually a report that summarizes the findings from any activities you conduct under your approved GAP and the results of those activities. We will protect the information from public disclosure as provided in § 285.113.
(c) You must annually (or other frequency as determined by MMS) submit a certification of compliance with those terms and conditions of your GAP that MMS identifies under
(1) Summary reports that show compliance with the terms and conditions which require certification; and
(2) A statement identifying and describing any mitigation measures and monitoring methods and their effectiveness. If you identified measures that were not effective, you must include your recommendations for new mitigation measures or monitoring methods.
(a) You must notify MMS in writing before conducting any activities not described in your approved GAP, describing in detail the type of activities you propose to conduct. We will determine whether the activities you propose are authorized by your existing GAP or require a revision to your GAP. We may request additional information from you, if necessary, to make this determination.
(b) The MMS will periodically review the activities conducted under an approved GAP. The frequency and extent of the review will be based on the significance of any changes in available information and on onshore or offshore conditions affecting, or affected by, the activities conducted under your GAP. If the review indicates that the GAP should be revised to meet the requirement of this part, we will require you to submit the needed revisions.
(c) Activities for which a proposed revision to your GAP will likely be necessary include:
(1) Activities not described in your approved GAP;
(2) Modifications to the size or type of facility or equipment you will use;
(3) Change in the surface location of a facility or structure;
(4) Addition of a facility or structure not contemplated in your approved GAP;
(5) Change in the location of your onshore support base from one State to another or to a new base requiring expansion;
(6) Changes in the locations of bottom disturbances (anchors, chains, etc.) by 500 feet (152 meters) or greater from the approved locations. If a specific anchor pattern was approved as a mitigation measure to avoid contact with bottom features, any change in the proposed bottom disturbances would likely trigger the need for a revision;
(7) Structural failure of one or more facilities; or
(8) Change to any other activity specified by MMS.
(d) We may begin the appropriate NEPA analysis and any relevant consultations when we determine that a proposed revision could:
(1) Result in a significant change in the impacts previously identified and evaluated;
(2) Require any additional Federal authorizations; or
(3) Involve activities not previously identified and evaluated.
(e) When you propose a revision, we may approve the revision if we determine that the revision is:
(1) Designed not to cause undue harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance; and
(2) Otherwise consistent with the provisions of subsection 8(p) of the OCS Lands Act.
You must notify the MMS any time you cease activities under your approved GAP without an approved suspension. If you cease activities for an indefinite period that exceeds 6 months, MMS may cancel your lease or grant under § 285.437, as applicable, and you must initiate the decommissioning process, as set forth in subpart I of this part.
Upon completion of your approved activities under your GAP, you must initiate the decommissioning process as set forth in subpart I of this part.
(a) You must make every effort to ensure that all cables and pipelines are constructed in a manner that minimizes deviations from the approved plan under your lease or grant.
(b) If MMS determines that a significant change in conditions has occurred that would necessitate an adjustment to your ROW, RUE or lease before the commencement of construction of the cable or pipeline on the grant or lease, MMS will consider modifications to your ROW grant, RUE grant, or your lease addendum for a project easement in connection with your COP or GAP.
(c) If, after construction, it is determined that a deviation from the approved plan has occurred, you must:
(1) Notify the operators of all leases (including mineral leases issued under this subchapter) and holders of all ROW grants or RUE grants (including all grants issued under this subchapter) which include the area where a deviation has occurred and provide MMS with evidence of such notification;
(2) Relinquish any unused portion of your lease or grant; and
(3) Submit a revised plan for MMS approval as necessary.
(d) Construction of a cable or pipeline that substantially deviates from the approved plan may be grounds for cancellation of the lease or grant.
(a) You must comply with the Clean Air Act (42 U.S.C. 7409) and its implementing regulations, according to the following table.
(b) For air quality modeling that you perform in support of the activities proposed in your plan, you should contact the appropriate regulatory agency to establish a modeling protocol to ensure that the agency's needs are met and that the meteorological files used are acceptable before initiating the modeling work. In the western Gulf of Mexico (west of 87.5° west longitude), you must submit to MMS three copies of the modeling report and three sets of digital files as supporting information. The digital files must contain the formatted meteorological files used in the modeling runs, the model input file, and the model output file.
(a) You must submit the following reports to MMS before installing facilities described in your approved COP (§ 285.632(a)) and, when required by this part, your SAP (§ 285.614(b)) or GAP (§ 285.651):
(1) A Facility Design Report; and
(2) A Fabrication and Installation Report.
(b) You may begin to fabricate and install the approved facilities after MMS notifies you that it has received your reports and has no objections. If
(c) If MMS has any objections, we will notify you verbally or in writing within 60 days of receipt of the report. Following initial notification of objections, MMS may follow up with written correspondence outlining its specific objections to the report and request that certain actions be undertaken. You cannot commence activities addressed in such report until you resolve all objections to MMS's satisfaction.
(a) Your Facility Design Report provides specific details of the design of any facilities, including cables and pipelines, that are outlined in your approved SAP, COP, or GAP. Your Facility Design Report must demonstrate that your design conforms to your responsibilities listed in § 285.105(a). You must include the following items in your Facility Design Report:
(b) For any floating facility, your design must meet the requirements of the U.S. Coast Guard for structural integrity and stability (e.g., verification of center of gravity). The design must also consider:
(1) Foundations, foundation pilings and templates, and anchoring systems; and
(2) Mooring or tethering systems.
(c) You must provide the location of records, as required in § 285.714(c).
(d) If you are required to use a CVA, the Facility Design Report must include one paper copy of the following certification statement: “The design of this structure has been certified by a MMS approved CVA to be in accordance with accepted engineering practices and the approved SAP, GAP, or COP as appropriate. The certified design and as-built plans and specifications will be on file at (given location).”
(e) The MMS will withhold trade secrets and commercial or financial information that is privileged or confidential from public disclosure under exemption 4 of the FOIA and in accordance with the terms of § 285.113.
(a) Your Fabrication and Installation Report must describe how your facilities will be fabricated and installed in accordance with the design criteria identified in the Facility Design Report; your approved SAP, COP, or GAP; and generally accepted industry standards and practices. Your Fabrication and Installation Report must demonstrate how your facilities will be fabricated and installed in a manner that conforms to your responsibilities listed in § 285.105(a). You must include the following items in your Fabrication and Installation Report:
(b) You must provide the location of records, as required in § 285.714(c).
(c) If you are required to use a CVA, the Fabrication and Installation Report must include one paper copy of the following certification statement: “The fabrication and installation of this structure has been certified by a MMS approved CVA to be in accordance with accepted engineering practices and the approved SAP, GAP, or COP as appropriate. The certified design and as-built plans and specifications will be on file at (given location).”
(d) The MMS will withhold trade secrets and commercial or financial information that is privileged or confidential from public disclosure under exemption 4 of the FOIA and in accordance with the terms of § 285.113.
(a) You must verify and, in a report to us, certify that major repairs and major modifications to the project conform to accepted engineering practices.
(1) A major repair is a corrective action involving structural members affecting the structural integrity of a portion of or all the facility.
(2) A major modification is an alteration involving structural members affecting the structural integrity of a portion of or all the facility.
(b) The report must also identify the location of all records pertaining to the major repairs or major modifications, as required in § 285.714(c).
(c) The MMS may require you to use a CVA for project modifications and repairs.
You must use a CVA to review and certify the Facility Design Report, the Fabrication and Installation Report, and the Project Modifications and Repairs Report.
(a) You must use a CVA to:
(1) Ensure that your facilities are designed, fabricated, and installed in conformance with accepted engineering practices and the Facility Design Report and Fabrication and Installation Report;
(2) Ensure that repairs and major modifications are completed in conformance with accepted engineering practices; and
(3) Provide MMS immediate reports of all incidents that affect the design, fabrication, and installation of the project and its components.
(b) The MMS may waive the requirement that you use a CVA if you can demonstrate the following:
(c) You must submit a request to waive the requirement to use a CVA to MMS in writing, along with your SAP under § 285.610(a)(9), COP under § 285.626(b)(20), or GAP under § 285.645(c)(5).
(1) The MMS will review your request to waive the use of the CVA and notify you of our decision along with our decision on your SAP, COP, or GAP.
(2) If MMS does not waive the requirement for a CVA, you may file an appeal under § 285.118.
(3) If MMS waives the requirement that you use a CVA, your project engineer must perform the same duties and responsibilities as the CVA, except as otherwise provided.
(a) As part of your COP (as provided in § 285.626(b)(20) and, when required by this part, your SAP (§ 285.610(a)(9)) or GAP (§ 285.645(c)(5)), you must nominate a CVA for MMS approval. You must specify whether the nomination is for the Facility Design Report, Fabrication and Installation Report, Modification and Repair Report, or for any combination of these.
(b) For each CVA that you nominate, you must submit to MMS a list of documents used in your design that you will forward to the CVA and a qualification statement that includes the following:
(1) Previous experience in third-party verification or experience in the design, fabrication, installation, or major modification of offshore energy facilities;
(2) Technical capabilities of the individual or the primary staff for the specific project;
(3) Size and type of organization or corporation;
(4) In-house availability of, or access to, appropriate technology (including computer programs, hardware, and testing materials and equipment);
(5) Ability to perform the CVA functions for the specific project considering current commitments;
(6) Previous experience with MMS requirements and procedures, if any; and
(7) The level of work to be performed by the CVA.
(c) Individuals or organizations acting as CVAs must not function in any capacity that will create a conflict of interest, or the appearance of a conflict of interest.
(d) The verification must be conducted by or under the direct supervision of registered professional engineers.
(e) The MMS will approve or disapprove your CVA as part of its review of the COP or, when required, of your SAP or GAP.
(f) You must nominate a new CVA for MMS approval if the previously approved CVA:
(1) Is no longer able to serve in a CVA capacity for the project; or
(2) No longer meets the requirements for a CVA set forth in this subpart.
If you are required to use a CVA:
(a) The CVA must use good engineering judgment and practices in conducting an independent assessment of the design of the facility. The CVA must certify in the Facility Design Report to MMS that the facility is designed to withstand the environmental and functional load conditions appropriate for the intended service life at the proposed location.
(b) The CVA must conduct an independent assessment of all proposed:
(1) Planning criteria;
(2) Operational requirements;
(3) Environmental loading data;
(4) Load determinations;
(5) Stress analyses;
(6) Material designations;
(7) Soil and foundation conditions;
(8) Safety factors; and
(9) Other pertinent parameters of the proposed design.
(c) For any floating facility, the CVA must ensure that any requirements of the U.S. Coast Guard for structural integrity and stability (e.g., verification of center of gravity), have been met. The CVA must also consider:
(1) Foundations, foundation pilings and templates, and anchoring systems; and
(2) Mooring or tethering systems.
(a) The CVA or project engineer must do all of the following:
(1) Use good engineering judgment and practice in conducting an independent assessment of the fabrication and installation activities;
(2) Monitor the fabrication and installation of the facility as required by paragraph (b) of this section;
(3) Make periodic onsite inspections while fabrication is in progress and verify the items required by § 285.709;
(4) Make periodic onsite inspections while installation is in progress and satisfy the requirements of § 295.710; and
(5) Certify in a report that project components are fabricated and installed in accordance with accepted engineering practices; your approved COP, SAP, or GAP (as applicable); and the Fabrication and Installation Report.
(i) The report must also identify the location of all records pertaining to fabrication and installation, as required in § 285.714(c); and
(ii) You may commence commercial operations or other approved activities 30 days after MMS receives that certification report, unless MMS notifies you within that time period of its objections to the certification report.
(b) To comply with paragraph (a)(5) of this section, the CVA or project engineer must monitor the fabrication and installation of the facility to ensure that it has been built and installed according to the Facility Design Report and Fabrication and Installation Report.
(1) If the CVA or project engineer finds that fabrication and installation procedures have been changed or design specifications have been modified, the
(2) If you accept the modifications, then you must also inform MMS.
(a) To comply with § 285.708(a)(3), the CVA or project engineer must make periodic onsite inspections while fabrication is in progress and must verify the following fabrication items, as appropriate:
(1) Quality control by lessee (or grant holder) and builder;
(2) Fabrication site facilities;
(3) Material quality and identification methods;
(4) Fabrication procedures specified in the Fabrication and Installation Report, and adherence to such procedures;
(5) Welder and welding procedure qualification and identification;
(6) Structural tolerances specified, and adherence to those tolerances;
(7) Nondestructive examination requirements and evaluation results of the specified examinations;
(8) Destructive testing requirements and results;
(9) Repair procedures;
(10) Installation of corrosion-protection systems and splash-zone protection;
(11) Erection procedures to ensure that overstressing of structural members does not occur;
(12) Alignment procedures;
(13) Dimensional check of the overall structure, including any turrets, turret-and-hull interfaces, any mooring line and chain and riser tensioning line segments; and
(14) Status of quality-control records at various stages of fabrication.
(b) For any floating facilities, the CVA or project engineer must ensure that any requirements of the U.S. Coast Guard for structural integrity and stability (e.g., verification of center of gravity) have been met. The CVA or project engineer must also consider:
(1) Foundations, foundation pilings and templates, and anchoring systems; and
(2) Mooring or tethering systems.
To comply with § 285.708(a)(4), the CVA or project engineer must make periodic onsite inspections while installation is in progress and must, as appropriate, verify, witness, survey, or check, the installation items required by this section.
(a) The CVA or project engineer must verify, as appropriate, all of the following:
(1) Loadout and initial flotation procedures;
(2) Towing operation procedures to the specified location, and review the towing records;
(3) Launching and uprighting activities;
(4) Submergence activities;
(5) Pile or anchor installations;
(6) Installation of mooring and tethering systems;
(7) Final deck and component installations; and
(8) Installation at the approved location according to the Facility Design Report and the Fabrication and Installation Report.
(b) For a fixed or floating facility, the CVA or project engineer must verify that proper procedures were used during the following:
(1) The loadout of the jacket, decks, piles, or structures from each fabrication site; and
(2) The actual installation of the facility or major modification and the related installation activities.
(c) For a floating facility, the CVA or project engineer must verify that proper procedures were used during the following:
(1) The loadout of the facility;
(2) The installation of foundation pilings and templates, and anchoring systems; and
(3) The installation of the mooring and tethering systems.
(d) The CVA or project engineer must conduct an onsite survey of the facility after transportation to the approved location.
(e) The CVA or project engineer must spot-check the equipment, procedures,
(a) The CVA or project engineer must prepare and submit to you and MMS all reports required by this subpart. The CVA or project engineer must also submit interim reports to you and MMS, as requested by the MMS.
(b) For each report required by this subpart, the CVA or project engineer must submit one electronic copy and one paper copy of each final report to MMS. In each report, the CVA or project engineer must:
(1) Give details of how, by whom, and when the CVA or project engineer activities were conducted;
(2) Describe the CVA's or project engineer's activities during the verification process;
(3) Summarize the CVA's or project engineer's findings; and
(4) Provide any additional comments that the CVA or project engineer deems necessary.
After the CVA or project engineer files the certification report, you must notify MMS within 10 business days after commencing commercial operations.
(a) Until MMS releases your financial assurance under § 285.534, you must compile, retain, and make available to MMS representatives, within the time specified by MMS, all of the following:
(1) The as-built drawings;
(2) The design assumptions and analyses;
(3) A summary of the fabrication and installation examination records;
(4) The inspection results from the inspections and assessments required by §§ 285.820 through 285.825; and
(5) Records of repairs not covered in the inspection report submitted under § 285.824(b)(3).
(b) You must record and retain the original material test results of all primary structural materials during all stages of construction until MMS releases your financial assurance under § 285.534. Primary material is material that, should it fail, would lead to a significant reduction in facility safety, structural reliability, or operating capabilities. Items such as steel brackets, deck stiffeners and secondary braces or beams would not generally be considered primary structural members (or materials).
(c) You must provide MMS with the location of these records in the certification statement, as required in §§ 285.701(c), 285.703(b), and 285.708(a)(5)(i).
(a) You must conduct all activities on your lease or grant under this part in a manner that conforms with your responsibilities in § 285.105(a), and using:
(1) Trained personnel; and
(2) Technologies, precautions, and techniques that will not cause undue harm or damage to natural resources, including their physical, atmospheric, and biological components.
(b) You must certify compliance with those terms and conditions identified in your approved SAP, COP, or GAP, as required under §§ 285.615(c), 285.633(b), or 285.653(c).
(a) You must not conduct any activity under your lease or grant that may affect threatened or endangered species or that may affect designated critical
(b) You must not conduct any activity under your lease or grant that may result in an incidental taking of marine mammals until the appropriate authorization has been issued under the Marine Mammal Protection Act of 1972 (MMPA) as amended (16 U.S.C. 1361
(c) If there is reason to believe that a threatened or endangered species may be present while you conduct your MMS approved activities or may be affected by the direct or indirect effects of your actions:
(1) You must notify us that endangered or threatened species may be present in the vicinity of the lease or grant or may be affected by your actions; and
(2) We will consult with appropriate State and Federal fish and wildlife agencies and, after consultation, shall identify whether, and under what conditions, you may proceed.
(d) If there is reason to believe that designated critical habitat of a threatened or endangered species may be affected by the direct or indirect effects of your MMS approved activities:
(1) You must notify us that designated critical habitat of a threatened or endangered species in the vicinity of the lease or grant may be affected by your actions; and
(2) We will consult with appropriate State and Federal fish and wildlife agencies and, after consultation, shall identify whether, and under what conditions, you may proceed.
(e) If there is reason to believe that marine mammals may be incidentally taken as a result of your proposed activities:
(1) You must agree to secure an authorization from National Oceanic and Atmospheric Administration (NOAA) or the U.S. Fish and Wildlife Service (FWS) for incidental taking, including taking by harassment, that may result from your actions; and
(2) You must comply with all measures required by the NOAA or FWS, including measures to affect the least practicable impact on such species and its habitat and to ensure no unmitigable adverse impact on the availability of the species for subsistence use.
(f) Submit to us:
(1) Measures designed to avoid or minimize adverse effects and any potential incidental take of the endangered or threatened species or marine mammals;
(2) Measures designed to avoid likely adverse modification or destruction of designated critical habitat of such endangered or threatened species; and
(3) Your agreement to monitor for the incidental take of the species and adverse effects on the critical habitat, and provide the results of the monitoring to MMS as required; and
(4) Your agreement to perform any relevant terms and conditions of the Incidental Take Statement that may result from the ESA consultation.
(5) Your agreement to perform any relevant mitigation measures under an MMPA incidental take authorization.
(a) If you, your subcontractors, or any agent acting on your behalf discovers a potential archaeological resource while conducting construction activities, or any other activity related to your project, you must:
(1) Immediately halt all seafloor-disturbing activities within the area of the discovery;
(2) Notify MMS of the discovery within 72 hours; and
(3) Keep the location of the discovery confidential and not take any action that may adversely affect the archaeological resource until we have made an evaluation and instructed you on how to proceed.
(b) We may require you to conduct additional investigations to determine if the resource is eligible for listing in the National Register of Historic Places under 36 CFR 60.4. We will do this if:
(1) The site has been impacted by your project activities; or
(2) Impacts to the site or to the area of potential effect cannot be avoided.
(c) If investigations under paragraph (b) of this section indicate that the resource is potentially eligible for listing in the National Register of Historic Places, we will tell you how to protect the resource, or how to mitigate adverse effects to the site.
(d) If we incur costs in protecting the resource, under section 110(g) of the NHPA, we may charge you reasonable costs for carrying out preservation responsibilities under the OCS Lands Act.
(a) If, during the conduct of your approved activities, MMS finds that essential fish habitat or habitat areas of particular concern may be adversely affected by your activities, MMS must consult with National Marine Fisheries Service.
(b) Any conservation recommendations adopted by MMS to avoid or minimize adverse affects on Essential Fish Habitat will be incorporated as terms and conditions in the lease and must be adhered to by the applicant. The MMS may require additional surveys to define boundaries and avoidance distances.
(c) If required, MMS will specify the survey methods and instrumentations for conducting the biological survey and will specify the contents of the biological report.
You must submit a description of the Safety Management System you will use with your COP (provided under § 285.627(d)) and, when required by this part, your SAP (as provided in § 285.614(b)) or GAP (as provided in § 285.651). You must describe:
(a) How you will ensure the safety of personnel or anyone on or near your facilities;
(b) Remote monitoring, control, and shut down capabilities;
(c) Emergency response procedures;
(d) Fire suppression equipment, if needed;
(e) How and when you will test your Safety Management System; and
(f) How you will ensure personnel who operate your facilities are properly trained.
Your Safety Management System must be fully functional when you begin activities described in your approved COP, SAP, or GAP. You must conduct all activities described in your approved COP, SAP, or GAP in accordance with the Safety Management System you described, as required by § 285.810.
(a) The removal of any equipment from service may result in MMS applying remedies, as provided in this part, when such equipment is necessary for implementing your approved plan. Such remedies may include an order from MMS requiring you to replace or remove such equipment or facilities.
(b)(1) You must report within 24 hours when equipment necessary for implementing your approved plan is removed from service for more than 12 hours. If you provide an oral notification, you must submit a written confirmation of this notice within 3 business days, as required by § 285.105(c);
(2) You do not have to report removing equipment necessary for implementing your plan if the removal is part of planned maintenance or repair activities; and
(3) You must notify MMS when you return the equipment to service.
(a) If you have facility damage or the failure of a pipeline, cable, or other equipment necessary for you to implement your approved plan, you must make repairs as soon as practicable. If you have a major repair, you must submit a report of the repairs to MMS, as required in § 285.711.
(b) If you are required to report any facility damage or failure under § 285.831, MMS may require you to revise your SAP, COP, or GAP to describe how you will address the facility damage or failure as required by § 285.634 (COP), § 285.617 (SAP), § 285.655 (GAP). You must submit a report of the repairs to MMS, as required in § 285.703.
(c) The MMS may require that you analyze cable, pipeline, or facility damage or failure to determine the cause. If requested by MMS, you must submit a comprehensive written report of the failure or damage to MMS as soon as available.
If environmental or other conditions adversely affect a cable, pipeline, or facility so as to endanger the safety or the environment, you must:
(a) Submit a plan of corrective action to MMS within 30 days of the discovery of the adverse effect.
(b) Take remedial action as described in your corrective action plan.
(c) Submit to the MMS a report of the remedial action taken within 30 days after completion.
The MMS will inspect OCS facilities and any vessels engaged in activities authorized under this part. We conduct these inspections:
(a) To verify that you are conducting activities in compliance with subsection 8(p) of the OCS Lands Act; the regulations in this part; the terms, conditions, and stipulations of your lease or grant; approved plans; and other applicable laws and regulations.
(b) To determine whether proper safety equipment has been installed and is operating properly according to your Safety Management System, as required in § 285.810.
The MMS will conduct both scheduled and unscheduled inspections.
(a) When MMS conducts an inspection, you must:
(1) Provide access to all facilities on your lease (including your project easement) or grant; and
(2) Make the following available for MMS to inspect:
(i) The area covered under a lease, ROW grant, or RUE grant;
(ii) All improvements, structures, and fixtures on these areas; and
(iii) All records of design, construction, operation, maintenance, repairs, or investigations on or related to the area.
(b) You must retain these records in paragraph (a)(2)(iii) of this section until MMS releases your financial assurance under § 285.534 and provide them to MMS upon request, within the time period specified by MMS.
(c) You must demonstrate to the inspector how you are in compliance with your Safety Management System.
Upon request, MMS will reimburse you for food, quarters, and transportation that you provide for our representatives while they inspect your lease or grant facilities and associated activities. You must send us your reimbursement request within 90 days of the inspection.
(a) You must develop a comprehensive annual self-inspection plan covering all of your facilities. You must keep this plan wherever you keep your records and make it available to MMS inspectors upon request. Your plan must specify:
(1) The type, extent, and frequency of in-place inspections that you will conduct for both the above-water and the below-water structures of all facilities and pertinent components of the mooring systems for any floating facilities; and
(2) How you are monitoring the corrosion protection for both the above-water and below-water structures.
(b) You must submit a report annually to us no later than November 1 that must include:
(1) A list of facilities inspected in the preceding 12 months;
(2) The type of inspection employed, (
(3) A summary of the inspection indicating what repairs, if any, were needed and the overall structural condition of the facility.
(a) You must perform an assessment of the structure, when needed, based on the platform assessment initiators listed in sections 17.2.1-17.2.5 of API RP 2A-WSD, Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms—Working Stress Design (incorporated by reference, as specified in § 285.115).
(b) You must initiate mitigation actions for structures that do not pass the assessment process of API RP 2A-WSD.
(c) You must perform other assessments as required by MMS.
(a) You must report all incidents listed in § 285.831 to MMS, according to the reporting requirements for these incidents in §§ 285.832 and 285.833.
(b) These reporting requirements apply to incidents that occur on the area covered by your lease or grant under this part and that are related to activities resulting from the exercise of your rights under your lease or grant under this part.
(c) Nothing in this subpart relieves you from providing notices and reports of incidents that may be required by other regulatory agencies.
(d) You must report all spills of oil or other liquid pollutants in accordance with 30 CFR 254.46.
(a) You must report the following incidents to us immediately via oral communication, and provide a written follow-up report (paper copy or electronically transmitted) within 15 business days after the incident:
(1) Fatalities;
(2) Incidents that require the evacuation of person(s) from the facility to shore or to another offshore facility;
(3) Fires and explosions;
(4) Collisions that result in property or equipment damage greater than $25,000 (
(5) Incidents involving structural damage to an OCS facility that is severe enough so that activities on the facility cannot continue until repairs are made;
(6) Incidents involving crane or personnel/material handling activities, if they result in a fatality, injury, structural damage, or significant environmental damage;
(7) Incidents that damage or disable safety systems or equipment (including firefighting systems);
(8) Other incidents resulting in property or equipment damage greater than $25,000; and
(9) Any other incidents involving significant environmental damage, or harm.
(b) You must provide a written report of the following incidents to us within 15 days after the incident:
(1) Any injuries that result in the injured person not being able to return to work or to all of their normal duties the day after the injury occurred; and
(2) All incidents that require personnel on the facility to muster for evacuation for reasons not related to weather or drills.
For an incident requiring immediate notification under § 285.831(a), you must notify MMS verbally after aiding the injured and stabilizing the situation. Your verbal communication must provide the following information:
(a) Date and time of occurrence;
(b) Identification and contact information for the lessee, grant holder, or operator;
(c) Contractor, and contractor representative's name and telephone number (if a contractor is involved in the incident or injury/fatality);
(d) Lease number, OCS area, and block;
(e) Platform/facility name and number, or cable or pipeline segment number;
(f) Type of incident or injury/fatality;
(g) Activity at time of incident; and
(h) Description of the incident, damage, or injury/fatality.
(a) For any incident covered under § 285.831, you must submit a written report within 15 days after the incident to MMS. The report must contain the following information:
(1) Date and time of occurrence;
(2) Identification and contact information for each lessee, grant holder, or operator;
(3) Name and telephone number of the contractor and the contractor's representative, if a contractor is involved in the incident or injury;
(4) Lease number, OCS area, and block;
(5) Platform/facility name and number, or cable or pipeline segment number;
(6) Type of incident or injury;
(7) Activity at time of incident;
(8) Description of incident, damage, or injury (including days away from work, restricted work, or job transfer), and any corrective action taken; and
(9) Property or equipment damage estimate (in U.S. dollars).
(b) You may submit a report or form prepared for another agency in lieu of the written report required by paragraph (a) of this section if the report or form contains all required information.
(c) The MMS may require you to submit additional information about an incident on a case-by-case basis.
(a) Lessees are jointly and severally responsible for meeting decommissioning obligations for facilities on their leases, including all obstructions, as the obligations accrue and until each obligation is met.
(b) Grant holders are jointly and severally liable for meeting decommissioning obligations for facilities on their grant, including all obstructions, as the obligations accrue and until each obligation is met.
You accrue decommissioning obligations when you are or become a lessee or grant holder, and you either install, construct, or acquire by an MMS-approved assignment a facility, cable, or pipeline, or you create an obstruction to other uses of the OCS.
(a) Except as otherwise authorized by MMS under § 285.909, within 2 years following termination of a lease or grant, you must:
(1) Remove or decommission all facilities, projects, cables, pipelines, and obstructions;
(2) Clear the seafloor of all obstructions created by activities on your lease, including your project easement, or grant, as required by the MMS.
(b) Before decommissioning the facilities under your SAP, COP, or GAP, you must submit a decommissioning application and receive approval from the MMS.
(c) The approval of the decommissioning concept in the SAP, COP, or GAP is not an approval of a decommissioning application. However, you may submit your complete decommissioning application simultaneously with the SAP, COP, or GAP so that it may undergo appropriate technical and regulatory reviews at that time.
(d) Following approval of your decommissioning application, you must submit a decommissioning notice under § 285.908 to MMS at least 60 days before commencing decommissioning activities.
(e) If you, your subcontractors, or any agent acting on your behalf discover any archaeological resource while conducting decommissioning activities, you must immediately halt bottom-disturbing activities within 1,000 feet of the discovery and report the discovery to us within 72 hours. We will inform you how to conduct investigations to determine if the resource is significant and how to protect it. You, your subcontractors, or any agent acting on your behalf must keep the location of the discovery confidential and must not take any action that may adversely affect the archaeological resource until we have made an evaluation and told you how to proceed.
(f) Provide MMS with documentation of any coordination efforts you have made with the affected States, local, and tribal governments.
You must comply with the decommissioning requirements in your MMS-issued lease. If you fail to comply with the decommissioning requirements of your lease then:
(a) The MMS may call for the forfeiture of your bond or other financial assurance;
(b) You remain liable for removal or disposal costs and responsible for accidents or damages that might result from such failure; and
(c) The MMS may take enforcement action under § 285.400 of this part.
You may request a departure from the decommissioning requirements under § 285.103.
You must submit your decommissioning application upon the earliest of the following dates:
(a) 2 years before the expiration of your lease.
(b) 90 days after completion of your commercial activities on a commercial lease.
(c) 90 days after completion of your approved activities under a limited lease on a ROW grant or RUE grant.
(d) 90 days after cancellation, relinquishment, or other termination of your lease or grant.
You must provide one paper copy and one electronic copy of the application. Include the following information in the application, as applicable.
(a) Identification of the applicant including:
(1) Lease operator, ROW grant holder, or RUE grant holder;
(2) Address;
(3) Contact person and telephone number; and
(4) Shore base.
(b) Identification and description of the facilities, cables, or pipelines you plan to remove or propose to leave in place, as provided in § 285.909.
(c) A proposed decommissioning schedule for your lease, ROW grant, or RUE grant, including the expiration or relinquishment date and proposed month and year of removal.
(d) A description of the removal methods and procedures, including the types of equipment, vessels, and moorings (
(e) A description of your site clearance activities.
(f) Your plans for transportation and disposal (including as an artificial reef) or salvage of the removed facilities, cables, or pipelines and any required approvals.
(g) A description of those resources, conditions, and activities that could be affected by or could affect your proposed decommissioning activities. The description must be as detailed as necessary to assist MMS in complying with the NEPA and other relevant Federal laws.
(h) The results of any recent biological surveys conducted in the vicinity of the structure and recent observations of turtles or marine mammals at the structure site.
(i) Mitigation measures you will use to protect archaeological and sensitive biological features during removal activities.
(j) A description of measures you will take to prevent unauthorized discharge of pollutants, including marine trash and debris, into the offshore waters.
(k) A statement of whether or not you will use divers to survey the area after removal to determine any effects on marine life.
(a) Based upon your inclusion of all the information required by § 285.906, MMS will compare your decommissioning application with the decommissioning general concept in your approved SAP, COP, or GAP to determine what technical and environmental reviews are needed.
(b) You will likely have to revise your SAP, COP, or GAP, and MMS will begin the appropriate NEPA analysis and other regulatory reviews as required, if MMS determines that your decommissioning application would:
(1) Result in a significant change in the impacts previously identified and evaluated in your SAP, COP, or GAP;
(2) Require any additional Federal permits; or
(3) Propose activities not previously identified and evaluated in your SAP, COP, or GAP.
(c) During the review process, we may request additional information if we determine that the information provided is not sufficient to complete the review and approval process.
(d) Upon completion of the technical and environmental reviews, we may approve, approve with conditions, or disapprove your decommissioning application.
(e) If MMS disapproves your decommissioning application, you must resubmit your application to address the concerns identified by MMS.
(a) The decommissioning notice is distinct from your decommissioning application and may only be submitted following approval of your decommissioning application, as described in §§ 285.905 through 285.907. You must submit a decommissioning notice at least 60 days before you plan to begin decommissioning activities.
(b) Your decommissioning notice must include:
(1) A description of any changes to the approved removal methods and procedures in your approved decommissioning application, including changes to the types of vessels and equipment you will use; and
(2) An updated decommissioning schedule.
(c) We will review your decommissioning notice and may require you to resubmit a decommissioning application if MMS determines that your decommissioning activities would:
(1) Result in a significant change in the impacts previously identified and evaluated;
(2) Require any additional Federal permits; or
(3) Propose activities not previously identified and evaluated.
(a) In your decommissioning application, you may request that certain facilities authorized in your lease or grant remain in place for other activities authorized in this part, elsewhere in this subchapter, or by other applicable Federal laws.
(b) The MMS may approve such requests on a case-by-case basis considering the following:
(1) Potential impacts to the marine environment;
(2) Competing uses of the OCS;
(3) Impacts on marine safety and national defense;
(4) Maintenance of adequate financial assurance; and
(5) Other factors determined by the Director.
(c) Except as provided in paragraph (d) of this section, if MMS authorizes facilities to remain in place, the former lessee or grantee under this part remains jointly and severally liable for decommissioning the facility unless satisfactory evidence is provided to MMS showing that another party has assumed that responsibility and has secured adequate financial assurances.
(d) In your decommissioning application, you may request that certain facilities authorized in your lease or grant be converted to an artificial reef or otherwise toppled in place. The MMS will evaluate all such requests, as provided in § 250.1730 of this subchapter.
(a) You must remove all facilities to a depth of 15 feet below the mudline, unless otherwise authorized by MMS.
(b) Within 60 days after you remove a facility, you must verify to MMS that you have cleared the site.
Within 60 days after you remove a facility, cable, or pipeline, you must submit a written report to MMS that includes the following:
(a) A summary of the removal activities, including the date they were completed;
(b) A description of any mitigation measures you took; and
(c) If you used explosives, a statement signed by your authorized representative that certifies that the types and amount of explosives you used in removing the facility were consistent with those in the approved decommissioning application.
If you fail to comply with your approved decommissioning plan or application:
(a) The MMS may call for the forfeiture of your bond or other financial assurance;
(b) You remain liable for removal or disposal costs and responsible for accidents or damages that might result from such failure; and
(c) The MMS may take enforcement action under § 285.400.
(a) This subpart provides the general provisions for authorizing and regulating activities that use (or propose to use) an existing OCS facility for energy- or marine-related purposes, that are not otherwise authorized under any other part of this subchapter
(b) The MMS will issue an Alternate Use RUE for activities authorized under this subpart.
(c) At the discretion of the Director, an Alternate Use RUE may:
(1) Permit alternate use activities to occur at an existing facility that is currently in use under an approved OCS lease; or
(2) Limit alternate use activities at the existing facility until after previously authorized activities at the facility have ceased and the OCS lease terminates.
If you are not the owner of the existing facility on the OCS and the lessee of the area in which the facility is located, you must contact the lessee and owner of the facility and reach a preliminary agreement as to the proposed activity for the use of the existing facility.
To request an Alternate Use RUE, you must submit to MMS all of the following:
(a) The name, address, e-mail address, and phone number of an authorized representative.
(b) A summary of the proposed activities for the use of an existing OCS facility, including:
(1) The type of activities that would involve the use of the existing OCS facility;
(2) A description of the existing OCS facility, including a map providing its location on the lease block;
(3) The names of the owner of the existing OCS facility, the operator, the lessee, and any owner of operating rights on the lease at which the facility is located;
(4) A description of additional structures or equipment that will be required to be located on or in the vicinity of the existing OCS facility in connection with the proposed activities;
(5) A statement indicating whether any of the proposed activities are intended to occur before existing activities on the OCS facility have ceased; and
(6) A statement describing how existing activities at the OCS facility will be affected if proposed activities are to occur at the same time as existing activities at the OCS facility.
(c) A statement affirming that the proposed activities sought to be approved under this subpart are not otherwise authorized by other provisions in this subchapter or any other Federal law.
(d) Evidence that you meet the requirements of § 285.106, as required by § 285.107.
(e) The signatures of the applicant, the owner of the existing OCS facility, and the lessee of the area in which the existing facility is located.
(a) We will consider requests for an Alternate Use RUE on a case-by-case basis. In considering such requests, we will consult with relevant Federal agencies and evaluate whether the proposed activities involving the use of an existing OCS facility can be conducted in a manner that:
(1) Ensures safety and minimizes adverse effects to the coastal and marine environments, including their physical, atmospheric, and biological components, to the extent practicable;
(2) Does not inhibit or restrain orderly development of OCS mineral or energy resources; and
(3) Avoids 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), or property (including sites, structures, or objects of historical or archaeological significance);
(4) Is otherwise consistent with subsection 8(p) of the OCS Lands Act; and
(5) MMS can effectively regulate.
(b) Based on the evaluation that we perform under paragraph (a) of this section, the MMS may authorize or reject, or authorize with modifications or stipulations, the proposed activity.
(a) An Alternate Use RUE must be issued on a competitive basis unless MMS determines, after public notice of the proposed Alternate Use RUE, that there is no competitive interest.
(b) We will issue a public notice in the
(c) If we receive indications of competitive interest within the published timeframe, we will proceed with a competitive offering. As part of such competitive offering, each competing applicant must submit a description of the types of activities proposed for the existing facility, as well as satisfactory evidence that the competing applicant qualifies to hold a lease or grant on the OCS, as required in §§ 285.106 and 285.107, by a date we specify. We may request additional information from competing applicants, as necessary, to adequately evaluate the competing proposals.
(d) We will evaluate all competing proposals to determine whether:
(1) The proposed activities are compatible with existing activities at the facility; and
(2) We have the expertise and resources available to regulate the activities effectively.
(e) We will evaluate all proposals under the requirements of NEPA, CZMA, and other applicable laws.
(f) Following our evaluation, we will select one or more acceptable proposals for activities involving the alternate use of an existing OCS facility, notify the competing applicants, and submit each acceptable proposal to the lessee and owner of the existing OCS facility. If the lessee and owner of the facility agree to accept a proposal, we will proceed to issue an Alternate Use RUE. If the lessee and owner of the facility are unwilling to accept any of the proposals that we deem acceptable, we will not issue an Alternate Use RUE.
(a) We will establish on a case-by-case basis, and set forth in the Alternate Use RUE, the length of time for which you are authorized to conduct activities approved in your Alternate Use RUE instrument.
(b) In establishing this term, MMS will consider the size and scale of the proposed alternate use activities, the type of alternate use activities, and any other relevant considerations.
(c) The MMS may authorize renewal of Alternate Use RUEs at its discretion.
We will establish rental or other payments for an Alternate Use RUE on a case-by-case basis, as set forth in the Alternate Use RUE grant, depending on our assessment of the following factors:
(a) The effect on the original OCS Lands Act approved activity;
(b) The size and scale of the proposed alternate use activities;
(c) The income, if any, expected to be generated from the proposed alternate use activities; and
(d) The type of alternate use activities.
(a) The holder of an Alternate Use RUE will be required to secure financial assurances in an amount determined by MMS that is sufficient to cover all obligations under the Alternate Use RUE, including decommissioning obligations, and must retain such financial assurance amounts until all obligations have been fulfilled, as determined by MMS.
(b) We may revise financial assurance amounts, as necessary, to ensure that there is sufficient financial assurance
(c) We may reduce the amount of the financial assurance that you must retain if it is not necessary to cover existing obligations under the Alternate Use RUE.
(a) The MMS may authorize assignment of an Alternate Use RUE.
(b) To request assignment of an Alternate Use RUE, you must submit a written request for assignment that includes the following information:
(1) The MMS-assigned Alternate Use RUE number;
(2) The names of both the assignor and the assignee, if applicable;
(3) The names and telephone numbers of the contacts for both the assignor and the assignee;
(4) The names, titles, and signatures of the authorizing officials for both the assignor and the assignee;
(5) A statement affirming that the owner of the existing OCS facility and lessee of the lease in which the facility is located approve of the proposed assignment and assignee;
(6) A statement that the assignee agrees to comply with and to be bound by the terms and conditions of the Alternate Use RUE;
(7) Evidence required by § 285.107 that the assignee satisfies the requirements of § 285.106; and
(8) A statement on how the assignee will comply with the financial assurance requirements set forth in the Alternate Use RUE.
(c) The assignment takes effect on the date we approve your request.
(d) The assignor is liable for all obligations that accrue under an Alternate Use RUE before the date we approve your assignment request. An assignment approval by MMS does not relieve the assignor of liability for accrued obligations that the assignee, or a subsequent assignee, fail to perform.
(e) The assignee and each subsequent assignee are liable for all obligations that accrue under an Alternate Use RUE after the date we approve the assignment request.
(a) The MMS may suspend an Alternate Use RUE if:
(1) Necessary to comply with judicial decrees;
(2) Continued activities pursuant to the Alternate Use RUE pose an imminent threat of serious or irreparable harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance;
(3) The suspension is necessary for reasons of national security or defense; or
(4) We have suspended or temporarily prohibited operation of the existing OCS facility that is subject to the Alternate Use RUE, and have determined that continued activities under the Alternate Use RUE are unsafe or cause undue interference with the operation of the original OCS Lands Act approved activity.
(b) A suspension will extend the term of your Alternate Use RUE grant for the period of the suspension.
(a) You may voluntarily surrender an Alternate Use RUE by submitting a written request to us that includes the following:
(1) The name, address, e-mail address, and phone number of an authorized representative;
(2) The reason you are requesting relinquishment of the Alternate Use RUE;
(3) The MMS-assigned Alternate Use RUE number;
(4) The name of the associated OCS facility, its owner, and the lessee for the lease in which the OCS facility is located;
(5) The name, title, and signature of your authorizing official (which must match exactly the name, title, and signature in the MMS qualification records); and
(6) A statement that you will adhere to the decommissioning requirements in the Alternate Use RUE.
(b) We will not approve your relinquishment request until you have paid
(c) The relinquishment takes effect on the date we approve your request.
The Secretary may cancel an Alternate Use RUE if it is determined, after notice and opportunity to be heard:
(a) You no longer qualify to hold an Alternate Use RUE;
(b) You failed to provide any additional financial assurance required by MMS, replace or provide additional coverage for a de-valued bond, or replace a lapsed or forfeited bond within the prescribed time period;
(c) Continued activity under the Alternate Use RUE is likely to cause serious harm or damage to natural resources; life (including human and wildlife); property; the marine, coastal, or human environment; or sites, structures, or objects of historical or archaeological significance;
(d) Continued activity under the Alternate Use RUE is determined to be adversely impacting the original OCS Lands Act approved activities on the existing OCS facility;
(e) You failed to comply with any of the terms and conditions of your approved Alternate Use RUE or your approved plan; or
(f) You otherwise failed to comply with applicable laws or regulations.
(a) The holder of an Alternate Use RUE is responsible for all decommissioning obligations that accrue following the issuance of the Alternate Use RUE and which pertain to the Alternate Use RUE.
(b) The lessee under the lease originally issued under part 250 of this chapter will remain responsible for decommissioning obligations that accrued before issuance of the Alternate Use RUE, as well as for decommissioning obligations that accrue following issuance of the Alternate Use RUE to the extent associated with continued activities authorized under other parts of this subchapter.
(a) Decommissioning requirements will be determined by MMS on a case-by-case basis, and will be included in the terms of each Alternate Use RUE.
(b) Decommissioning activities must be completed within 1 year of termination of the Alternate Use RUE.
(c) If you fail to satisfy all decommissioning requirements within the prescribed time period, we will call for the forfeiture of your bond or other financial guarantee, and you will remain liable for all accidents or damages that might result from such failure.
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), 281.21(a)(1), or 285.118(c), 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) You must pay electronically through
(2) You cannot extend the 60-day period for payment of the processing fee.
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.
31 U.S.C. 9701, 43 U.S.C. 1334.
(a) The Office of Management and Budget (OMB) has approved the information collection requirements in this part under 44 U.S.C. 3501
(b) 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.
(c) We use the information collected to determine whether or not the shipper has been denied open and nondiscriminatory access to Outer Continental Shelf (OCS) pipelines as sections of 5(e) and (f) of the OCS Lands Act (OCSLA) require.
(d) Respondents are companies that ship or transport oil and gas production across the OCS. Responses are required to obtain or retain benefits. We will protect information considered proprietary under applicable law.
(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 5438, 1849 C Street, NW., Washington, DC 20240.
This part:
(a) Explains the procedures for filing a complaint with the Director, Minerals Management Service (MMS) alleging that a grantee or transporter has denied a shipper of production from the OCS open and nondiscriminatory access to a pipeline;
(b) Explains the procedures MMS will employ to determine whether violations of the requirements of the OCSLA have occurred, and to remedy any violations; and
(c) Provides for alternative informal means of resolving pipeline access disputes through either Hotline-assisted procedures or alternative dispute resolution (ADR).
As used in this part:
Before filing a complaint under § 291.106, you may attempt to informally resolve an allegation concerning open and nondiscriminatory access by calling the toll-free MMS Hotline at 1-888-232-1713.
(a) MMS Hotline staff will informally seek information needed to resolve the
(b) MMS Hotline staff may provide information to you and give informal oral advice. The advice given is not binding on MMS, the Department of the Interior (DOI), or any other person.
(c) To the extent permitted by law, the MMS Hotline staff will treat all information it obtains as non-public and confidential.
(d) You may call the MMS Hotline anonymously.
(e) If you contact the MMS Hotline, you may file a complaint under this part if discussions assisted by MMS Hotline staff are unsuccessful at resolving the matter.
(f) You may terminate use of the MMS Hotline procedure at any time.
You may ask to use ADR either before or after you file a complaint. To make a request, call the MMS at 1-888-232-1713 or write to us at the following address: Associate Director, Policy and Management Improvement, Minerals Management Service, 1849 C Street, NW., Mail Stop 5438, Washington, DC 20240-0001.
(a) You may request that ADR be administered by:
(1) A contracted ADR provider agreed to by all parties;
(2) The Department's Office of Collaborative Action and Dispute Resolution (CADR); or
(3) MMS staff trained in ADR and certified by the CADR.
(b) Each party must pay its respective share of all costs and fees associated with any contracted or Departmental ADR provider. For purposes of this section, MMS is not a party in an ADR proceeding.
(a) You may file a complaint under this subpart if you are a shipper and you believe that you have been denied open and nondiscriminatory access to an OCSLA pipeline that is not a FERC pipeline.
(b) Any person that believes its interests may be affected by precedents established by adjudication of complaints under this rule may submit a brief to MMS. The brief must be served following the procedure set out in 30 CFR 291.107. After considering the brief, it is within MMS's discretion as to whether MMS may:
(1) Address the brief in its decision;
(2) Not address the brief in its decision; or
(3) Include the submitter of the brief in the proceeding as a party.
For purposes of this subpart, a complaint means a comprehensive written brief stating the legal and factual basis for the allegation that a shipper was denied open and nondiscriminatory access, together with supporting material. A complaint must:
(a) Clearly identify the action or inaction which is alleged to violate 43 U.S.C. 1334(e) or (f)(1)(A);
(b) Explain how the action or inaction violates 43 U.S.C. 1334(e) or (f)(1)(A);
(c) Explain how the action or inaction affects your interests, including practical, operational, or other non-financial impacts;
(d) Estimate any financial impact or burden;
(e) State the specific relief or remedy requested; and
(f) Include all documents that support the facts in your complaint including, but not limited to, contracts and any affidavits that may be necessary to support particular factual allegations.
To file a complaint under this part, you must:
(a) File your complaint with the Director, Minerals Management Service
(b) Include a nonrefundable processing fee of $7,500 under § 291.108(a) or a request for reduction or waiver of the fee under § 291.109(a); and
(c) Serve your complaint on all persons named in the complaint. If you make a claim under § 291.111 for confidentiality, serve the redacted copy and proposed form of a protective agreement on all persons named in the complaint.
(d) Complaints shall not be filed later than two (2) years from the time of the alleged access denial. If the complaint is filed later than two (2) years from the time of the alleged access denial, the MMS Director will not consider the complaint and the case will be closed.
(a) If you have been served a complaint under § 291.106, you must file an answer within 60 days of receiving the complaint. If you miss this deadline, MMS may disregard your answer. We consider your answer to be filed when the MMS Director receives it at the following address: Director, Minerals Management Service, Attention: Policy and Management Improvement, 1849 C Street, NW., Mail Stop 5438, Washington, DC 20240-0001.
(b) For purposes of this paragraph, an answer means a comprehensive written brief stating the legal and factual basis refuting the allegations in the complaint, together with supporting material. You must:
(1) Attach to your answer a copy of the complaint or reference the assigned MMS docket number (you may obtain the docket number by calling the Policy and Management Improvement Office at (202) 208-2622);
(2) Explain in your answer why the action or inaction alleged in the complaint does not violate 43 U.S.C. 1334(e) or (f)(1)(A);
(3) Include with your answer all documents in your possession or that you can otherwise obtain that support the facts in your answer including, but not limited to, contracts and any affidavits that may be necessary to support particular factual allegations; and
(4) Provide a copy of your answer to all parties named in the complaint including the complainant. If you make a claim under § 291.111 for confidentiality, serve the redacted copy and proposed form of a protective agreement to all parties named in the complaint, including the complainant.
(a) You must pay the processing fee electronically through
(b) You must include with the payment:
(1) Your taxpayer identification number;
(2) Your payor identification number, if applicable; and
(3) The complaint caption, or any other applicable identification of the complaint you are filing.
(a) MMS may grant a fee waiver or fee reduction in extraordinary circumstances. You may request a waiver or reduction of your fee by:
(1) Sending a written request to the MMS Policy and Management Improvement Office when you file your complaint; and
(2) Demonstrating in your request that you are unable to pay the fee or that payment of the full fee would impose an undue hardship upon you.
(b) The MMS Policy and Management Improvement Office will send you a written decision granting or denying your request for a fee waiver or a fee reduction.
(1) If we grant your request for a fee reduction, you must pay the reduced processing fee within 30 days of the date you receive our decision.
(2) If we deny your request, you must pay the entire processing fee within 30 days of the date you receive the decision.
(3) MMS's decision granting or denying a fee waiver or reduction is final for the Department.
(a) MMS may require any lessee, operator of a lease or unit, shipper, grantee, or transporter to provide information that MMS believes is necessary to make a decision on whether open access or nondiscriminatory access was denied.
(b) If you are a party and fail to provide information MMS requires under paragraph (a) of this section, MMS may:
(1) Assess civil penalties under 30 CFR part 250, subpart N;
(2) Dismiss your complaint or consider your answer incomplete; or
(3) Presume the required information is adverse to you on the factual issues to which the information is relevant.
(c) If you are not a party to a complaint and fail to provide information MMS requires under paragraph (a) of this section, MMS may assess civil penalties under 30 CFR part 250, subpart N.
(a) Any person who provides documents under this part in response to a request by MMS to inform a decision on whether open access or nondiscriminatory access was denied may claim that some or all of the information contained in a particular document is confidential. If you claim confidential treatment, then when you provide the document to MMS you must:
(1) Provide a complete unredacted copy of the document and indicate on that copy that you are making a request for confidential treatment for some or all of the information in the document.
(2) Provide a statement specifying the specific statutory justification for nondisclosure of the information for which you claim confidential treatment. General claims of confidentiality are not sufficient. You must furnish sufficient information for MMS to make an informed decision on the request for confidential treatment.
(3) Provide a second copy of the document from which you have redacted the information for which you wish to claim confidential treatment. If you do not submit a second copy of the document with the confidential information redacted, MMS may assume that there is no objection to public disclosure of the document in its entirety.
(b) In making data and information you submit available to the public, MMS will not disclose documents exempt from disclosure under the Freedom of Information Act (5 U.S.C. 552) and will follow the procedures set forth in the implementing regulations at 43 CFR part 2 to give submitters an opportunity to object to disclosure.
(c) MMS retains the right to make the determination with regard to any claim of confidentiality. MMS will notify you of its decision to deny a claim, in whole or in part, and, to the extent permitted by law, will give you an opportunity to respond at least 10 days before its public disclosure.
MMS will begin processing a complaint upon receipt of a processing fee or granting a waiver of the fee. The MMS Director will review the complaint, answer, and other information, and will serve all parties with a written decision that:
(a) Makes findings of fact and conclusions of law; and
(b) Renders a decision determining whether the complainant has been denied open and nondiscriminatory access.
If the MMS Director's decision under § 291.112 determines that the grantee or transporter has not provided open access or nondiscriminatory access, then the decision will describe the actions MMS will take to require the grantee or transporter to remedy the denial of open access or nondiscriminatory access. The remedies MMS would require
(a) Ordering grantees and transporters to provide open and nondiscriminatory access to the complainant;
(b) Assessing civil penalties of up to $10,000 per day under 30 CFR part 250, subpart N, for failure to comply with an MMS order to provide open access or nondiscriminatory access. Penalties will begin to accrue 60 days after the grantee or transporter receives the order to provide open and nondiscriminatory access if it has not provided such access by that time. However, if MMS determines that requiring the construction of facilities would be an appropriate remedy under the OCSLA, penalties will begin to accrue 10 days after conclusion of diligent construction of needed facilities or 60 days after the grantee or transporter receives the order to provide open and nondiscriminatory access, whichever is later, if it has not provided such access by that time;
(c) Requesting the Attorney General to institute a civil action in the appropriate United States District Court under 43 U.S.C. 1350(a) for a temporary restraining order, injunction, or other appropriate remedy to enforce the open and nondiscriminatory access requirements of 43 U.S.C. 1334(e) and (f)(1)(A); or
(d) Initiating a proceeding to forfeit the right-of-way grant under 43 U.S.C. 1334(e).
Any party, except as provided in § 291.115(b), adversely affected by a decision of the MMS Director under this part may appeal to the Interior Board of Land Appeals (IBLA) under the procedures in 43 CFR part 4, subpart E.
(a) If the MMS Director issues a decision under this part but does not expressly make the decision effective upon issuance, you must appeal the decision to the IBLA under 43 CFR part 4 to exhaust administrative remedies. Such decision will not be effective during the time in which a person adversely affected by the MMS Director's decision may file a notice of appeal with the IBLA, and the timely filing of a notice of appeal will suspend the effect of the decision pending the decision on appeal.
(b) This section does not apply if a decision was made effective by:
(1) The MMS Director; or
(2) The Assistant Secretary for Land and Minerals Management.
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
(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.
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.
Table of CFR Titles and Chapters
Alphabetical List of Agencies Appearing in the CFR
List of CFR Sections Affected
All changes in this volume of the Code of Federal Regulations that were made by documents published in the
For the period before January 1, 2001, see the “List of Sections Affected, 1949-1963, 1964-1972, 1973-1985, and 1986-2000,” published in 11 separate volumes.