June 28, 2007 CODE OF FEDERAL REGULATIONS 30 Parts 200 to 699 Revised as of July 1, 2007 Mineral Resources Containing a codification of documents of general applicability and future effect As of July 1, 2007 With Ancillaries

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 Table of Contents Page Explanation v Title 30: Chapter II—Minerals Management Service, Department of the Interior 3 Chapter III—Board of Surface Mining and Reclamation Appeals, Department of the Interior 597 Chapter IV—Geological Survey, Department of the Interior 601 Finding Aids: Material Approved for Incorporation by Reference 615 Table of CFR Titles and Chapters 623 Alphabetical List of Agencies Appearing in the CFR 641 List of CFR Sections Affected 651

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 INCORPORATION BY REFERENCE

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What is a proper incorporation by reference? The Director of the Federal Register will approve an incorporation by reference only when the requirements of 1 CFR part 51 are met. Some of the elements on which approval is based are:

(a) The incorporation will substantially reduce the volume of material published in the Federal Register.

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(c) The incorporating document is drafted and submitted for publication in accordance with 1 CFR part 51.

Properly approved incorporations by reference in this volume are listed in the Finding Aids at the end of this volume.

What if the material incorporated by reference cannot be found? If you have any problem locating or obtaining a copy of material listed in the Finding Aids of this volume as an approved incorporation by reference, please contact the agency that issued the regulation containing that incorporation. If, after contacting the agency, you find the material is not available, please notify the Director of the Federal Register, National Archives and Records Administration, Washington DC 20408, or call 202-741-6010.

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 Raymond A. Mosley, Director, Office of the Federal Register. July 1, 2007. THIS TITLE

Title 30—Mineral Resources is composed of three volumes. The parts in these volumes are arranged in the following order: parts 1 to 199, parts 200 to 699, and part 700 to End. The contents of these volumes represent all current regulations codified under this title of the CFR as of July 1, 2007.

For this volume, Cheryl E. Sirofchuck was Chief Editor. The Code of Federal Regulations publication program is under the direction of Frances D. McDonald, assisted by Ann Worley.

 <LRH>30 CFR Ch. II (7-1-07 Edition)</LRH> <RRH>Minerals Management Service, Interior</RRH> <CFRTITLE> <TITLEHD> <PRTPAGE P="1"/> <HD SOURCE="HED">Title 30—Mineral Resources</HD> <P>(This book contains parts 200 to 699)</P> </TITLEHD> <CFRTOC> <PTHD>Part</PTHD> <CHAPTI> <SUBJECT> <E T="04">chapter ii</E>—Minerals Management Service, Department of the Interior</SUBJECT> <PG>201</PG> </CHAPTI> <CHAPTI> <SUBJECT> <E T="04">chapter iii</E>—Board of Surface Mining and Reclamation Appeals, Department of the Interior</SUBJECT> <PG>301</PG> </CHAPTI> <CHAPTI> <SUBJECT> <E T="04">chapter iv</E>—Geological Survey, Department of the Interior</SUBJECT> <PG>401</PG> </CHAPTI> </CFRTOC> </CFRTITLE> <CHAPTER> <TOC> <TOCHD> <PRTPAGE P="3"/> <HD SOURCE="HED">CHAPTER II—MINERALS MANAGEMENT SERVICE, DEPARTMENT OF THE INTERIOR</HD> <P>(Parts 200 to 699)</P> </TOCHD> <SUBCHAP> <HD SOURCE="HED">SUBCHAPTER A—MINERALS REVENUE MANAGEMENT</HD> </SUBCHAP> <PTHD>Part</PTHD> <PGHD>Page</PGHD> <CHAPTI> <PT>201</PT> <SUBJECT>General</SUBJECT> <PG>5</PG> <PT>202</PT> <SUBJECT>Royalties</SUBJECT> <PG>5</PG> <PT>203</PT> <SUBJECT>Relief or reduction in royalty rates</SUBJECT> <PG>14</PG> <PT>204</PT> <SUBJECT>Alternatives for marginal properties</SUBJECT> <PG>44</PG> <PT>206</PT> <SUBJECT>Product valuation</SUBJECT> <PG>50</PG> <PT>207</PT> <SUBJECT>Sales agreements or contracts governing the disposal of lease products</SUBJECT> <PG>162</PG> <PT>208</PT> <SUBJECT>Sale of Federal royalty oil</SUBJECT> <PG>164</PG> <PT>210</PT> <SUBJECT>Forms and reports</SUBJECT> <PG>171</PG> <PT>212</PT> <SUBJECT>Records and files maintenance</SUBJECT> <PG>183</PG> <PT>215</PT> <RESERVED>Accounting and auditing standards [Reserved]</RESERVED> <PT>216</PT> <SUBJECT>Production accounting</SUBJECT> <PG>185</PG> <PT>217</PT> <SUBJECT>Audits and inspections</SUBJECT> <PG>192</PG> <PT>218</PT> <SUBJECT>Collection of royalties, rentals, bonuses and other monies due the Federal Government and credits and incentives due lessees</SUBJECT> <PG>194</PG> <PT>219</PT> <SUBJECT>Distribution and disbursement of royalties, rentals, and bonuses</SUBJECT> <PG>211</PG> <PT>220</PT> <SUBJECT>Accounting procedures for determining net profit share payment for Outer Continental Shelf oil and gas leases</SUBJECT> <PG>213</PG> <PT>227</PT> <SUBJECT>Delegation to States</SUBJECT> <PG>226</PG> <PT>228</PT> <SUBJECT>Cooperative activities with States and Indian tribes</SUBJECT> <PG>238</PG> <PT>229</PT> <SUBJECT>Delegation to States</SUBJECT> <PG>241</PG> <PT>230</PT> <RESERVED>Recoupments and refunds [Reserved]</RESERVED> <PT>232</PT> <RESERVED>Interest payments [Reserved]</RESERVED> <PT>233</PT> <RESERVED>Escrow and investments [Reserved]</RESERVED> <PT>234</PT> <RESERVED>Bonding—payment liability [Reserved]</RESERVED> <PT>241</PT> <SUBJECT>Penalties</SUBJECT> <PG>249</PG> <PT>242</PT> <RESERVED>Orders [Reserved]<PRTPAGE P="4"/> </RESERVED> <PT>243</PT> <SUBJECT>Suspensions pending appeal and bonding—Minerals revenue management</SUBJECT> <PG>254</PG> </CHAPTI> <SUBCHAP> <HD SOURCE="HED">SUBCHAPTER B—OFFSHORE</HD> </SUBCHAP> <CHAPTI> <PT>250</PT> <SUBJECT>Oil and gas and sulphur operations in the Outer Continental Shelf</SUBJECT> <PG>260</PG> <PT>251</PT> <SUBJECT>Geological and geophysical (G & G) explorations of the Outer Continental Shelf</SUBJECT> <PG>461</PG> <PT>252</PT> <SUBJECT>Outer Continental Shelf (OCS) oil and gas information program</SUBJECT> <PG>474</PG> <PT>253</PT> <SUBJECT>Oil spill financial responsibility for offshore facilities</SUBJECT> <PG>479</PG> <PT>254</PT> <SUBJECT>Oil-spill response requirements for facilities located seaward of the coast line</SUBJECT> <PG>493</PG> <PT>256</PT> <SUBJECT>Leasing of sulphur or oil and gas in the Outer Continental Shelf</SUBJECT> <PG>505</PG> <PT>259</PT> <SUBJECT>Mineral leasing: Definitions</SUBJECT> <PG>533</PG> <PT>260</PT> <SUBJECT>Outer Continental Shelf oil and gas leasing</SUBJECT> <PG>534</PG> <PT>270</PT> <SUBJECT>Nondiscrimination in the Outer Continental Shelf</SUBJECT> <PG>542</PG> <PT>280</PT> <SUBJECT>Prospecting for minerals other than oil, gas, and sulfur on the Outer Continental Shelf</SUBJECT> <PG>543</PG> <PT>281</PT> <SUBJECT>Leasing of minerals other than oil, gas, and sulphur in the Outer Continental Shelf</SUBJECT> <PG>555</PG> <PT>282</PT> <SUBJECT>Operations in the Outer Continental Shelf for minerals other than oil, gas, and sulphur</SUBJECT> <PG>568</PG> </CHAPTI> <SUBCHAP> <HD SOURCE="HED">SUBCHAPTER C—APPEALS</HD> </SUBCHAP> <CHAPTI> <PT>290</PT> <SUBJECT>Appeals procedures</SUBJECT> <PG>591</PG> </CHAPTI> </TOC> <SUBCHAP TYPE="N"> <PRTPAGE P="5"/> <HD SOURCE="HED">SUBCHAPTER A—MINERALS REVENUE MANAGEMENT</HD> <PART> <EAR>Pt. 201</EAR> <HD SOURCE="HED">PART 201—GENERAL</HD> <CONTENTS> <SUBPART> <RESERVED>Subpart A—General Provisions [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart B—Oil and Gas, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Oil and Gas, Onshore</HD> <SECHD>Sec.</SECHD> <SECTNO>201.100</SECTNO> <SUBJECT>Responsibilities of the Associate Director for Minerals Revenue Management.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart D—Oil, Gas and Sulphur, Offshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart F—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Geothermal Resources [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart H—Indian Lands [Reserved]</RESERVED> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>The Act of February 25, 1920 (30 U.S.C. 181, <E T="03">et seq.</E>), as amended; the Act of May 21, 1930 (30 U.S.C. 301-306); the Mineral Leasing Act for Acquired Lands (30 U.S.C. 351-359), as amended; the Act of March 3, 1909 (25 U.S.C. 396), as amended; the National Environmental Policy Act of 1969 (42 U.S.C. 4321, <E T="03">et seq.</E>) as amended; the Act of May 11, 1938 (25 U.S.C. 396a-396q), as amended; the Act of February 28, 1891 (25 U.S.C. 397), as amended; the Act of May 29, 1924 (25 U.S.C. 398); the Act of March 3, 1927 (25 U.S.C. 398a-398e); the Act of June 30, 1919 (25 U.S.C. 399), as amended; R.S. § 441 (43 U.S.C. 1457), see also Attorney General's Opinion of April 2, 1941 (40 Op. Atty. Gen. 41); the Federal Property and Administrative Services Act of 1949 (40 U.S.C. 471, <E T="03">et seq.</E>), as amended; the National Environmental Policy Act of 1969 (42 U.S.C. 4321 <E T="03">et seq.</E>), as amended; the Act of December 12, 1980 (Pub. L. 96-514, 94 Stat. 2964); the Combined Hydrocarbon Leasing Act of 1981 (Pub. L. 97-78, 95 Stat. 1070); the Outer Continental Shelf Lands Act (43 U.S.C. 1331, <E T="03">et seq.</E>), as amended; section 2 of Reorganization Plan No. 3 of 1950 (64 stat. 1262); Secretarial Order No. 3071 of January 19, 1982, as amended; and Secretarial Order 3087, as amended.</P> </AUTH> <SUBPART> <RESERVED>Subpart A—General Provisions [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart B—Oil and Gas, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Oil and Gas, Onshore</HD> <SECTION> <SECTNO>§ 201.100</SECTNO> <SUBJECT>Responsibilities of the Associate Director for Minerals Revenue Management.</SUBJECT> <P>The Associate Director is responsible for the collection of certain rents, royalties, and other payments; for the receipt of sales and production reports; for determining royalty liability; for maintaining accounting records; for any audits of the royalty payments and obligations; and for any and all other functions relating to royalty management on Federal and Indian oil and gas leases.</P> <CITA>[47 FR 47768, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart D—Oil, Gas and Sulphur, Offshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart F—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Geothermal Resources [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart H—Indian Lands [Reserved]</RESERVED> </SUBPART> </PART> <PART> <EAR>Pt. 202</EAR> <HD SOURCE="HED">PART 202—ROYALTIES</HD> <CONTENTS> <SUBPART> <RESERVED>Subpart A—General Provisions [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil, Gas, and OCS Sulfur, General</HD> <SECHD>Sec.</SECHD> <SECTNO>202.51</SECTNO> <SUBJECT>Scope and definitions.</SUBJECT> <SECTNO>202.52</SECTNO> <SUBJECT>Royalties.</SUBJECT> <SECTNO>202.53</SECTNO> <SUBJECT>Minimum royalty.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Federal and Indian Oil</HD> <SECTNO>202.100</SECTNO> <SUBJECT>Royalty on oil.</SUBJECT> <SECTNO>202.101</SECTNO> <SUBJECT>Standards for reporting and paying royalties.</SUBJECT> </SUBPART> <SUBPART> <PRTPAGE P="6"/> <HD SOURCE="HED">Subpart D—Federal Gas</HD> <SECTNO>202.150</SECTNO> <SUBJECT>Royalty on gas.</SUBJECT> <SECTNO>202.151</SECTNO> <SUBJECT>Royalty on processed gas.</SUBJECT> <SECTNO>202.152</SECTNO> <SUBJECT>Standards for reporting and paying royalties on gas.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Coal</HD> <SECTNO>202.250</SECTNO> <SUBJECT>Overriding royalty interest.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Geothermal Resources</HD> <SECTNO>202.350</SECTNO> <SUBJECT>Scope and definitions.</SUBJECT> <SECTNO>202.351</SECTNO> <SUBJECT>Royalties on geothermal resources.</SUBJECT> <SECTNO>202.352</SECTNO> <SUBJECT>Minimum royalty.</SUBJECT> <SECTNO>202.353</SECTNO> <SUBJECT>Measurement standards for reporting and paying royalties and direct use fees.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart J—Gas Production from Indian Leases</HD> <SECTNO>202.550</SECTNO> <SUBJECT>How do I determine the royalty due on gas production?</SUBJECT> <SECTNO>202.551</SECTNO> <SUBJECT>How do I determine the volume of production for which I must pay royalty if my lease is not in an approved Federal unit or communitization agreement (AFA)?</SUBJECT> <SECTNO>202.552</SECTNO> <SUBJECT>How do I determine how much royalty I must pay if my lease is in an approved Federal unit or communitization agreement (AFA)?</SUBJECT> <SECTNO>202.553</SECTNO> <SUBJECT>How do I value my production if I take more than my entitled share?</SUBJECT> <SECTNO>202.554</SECTNO> <SUBJECT>How do I value my production that I do not take if I take less than my entitled share?</SUBJECT> <SECTNO>202.555</SECTNO> <SUBJECT>What portion of the gas that I produce is subject to royalty?</SUBJECT> <SECTNO>202.556</SECTNO> <SUBJECT>How do I determine the value of avoidably lost, wasted, or drained gas?</SUBJECT> <SECTNO>202.557</SECTNO> <SUBJECT>Must I pay royalty on insurance compensation for unavoidably lost gas?</SUBJECT> <SECTNO>202.558</SECTNO> <SUBJECT>What standards do I use to report and pay royalties on gas?</SUBJECT> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>5 U.S.C. 301 <E T="03">et seq.</E>; 25 U.S.C. 396 <E T="03">et seq.,</E> 396a <E T="03">et seq.,</E> 2101 <E T="03">et seq.</E>; 30 U.S.C. 181 <E T="03">et seq.,</E> 351 <E T="03">et seq.,</E> 1001 <E T="03">et seq.</E>; 1701 <E T="03">et seq.</E>; 31 U.S.C. 9701; 43 U.S.C. 1301 <E T="03">et seq.</E>; 1331 <E T="03">et seq.,</E> 1801 <E T="03">et seq.</E> </P> </AUTH> <SUBPART> <RESERVED>Subpart A—General Provisions [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil, Gas, and OCS Sulfur, General</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>53 FR 1217, Jan. 15, 1988, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 202.51</SECTNO> <SUBJECT>Scope and definitions.</SUBJECT> <P>(a) This subpart is applicable to Federal and Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma) and OCS sulfur leases.</P> <P>(b) The definitions in subparts B, C, D, and E, of part 206 of this title are applicable to subparts B, C, D, and J of this part.</P> <CITA>[53 FR 1217, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 202.52</SECTNO> <SUBJECT>Royalties.</SUBJECT> <P>(a) Royalties on oil, gas, and OCS sulfur shall be at the royalty rate specified in the lease, unless the Secretary, pursuant to the provisions of the applicable mineral leasing laws, reduces, or in the case of OCS leases, reduces or eliminates, the royalty rate or net profit share set forth in the lease.</P> <P>(b) For purposes of this subpart, the use of the term <E T="03">royalty(ies)</E> includes the term <E T="03">net profit share(s)</E>.</P> </SECTION> <SECTION> <SECTNO>§ 202.53</SECTNO> <SUBJECT>Minimum royalty.</SUBJECT> <P>For leases that provide for minimum royalty payments, the lessee shall pay the minimum royalty as specified in the lease.</P> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Federal and Indian Oil</HD> <SECTION> <SECTNO>§ 202.100</SECTNO> <SUBJECT>Royalty on oil.</SUBJECT> <P>(a) Royalties due on oil production from leases subject to the requirements of this part, including condensate separated from gas without processing, shall be at the royalty rate established by the terms of the lease. Royalty shall be paid in value unless MMS requires payment in-kind. When paid in value, the royalty due shall be the value, for royalty purposes, determined pursuant to part 206 of this title multiplied by the royalty rate in the lease.</P> <P>(b)(1) All oil (except oil unavoidably lost or used on, or for the benefit of, the lease, including that oil used off-lease for the benefit of the lease when such off-lease use is permitted by the <PRTPAGE P="7"/>MMS or BLM, as appropriate) produced from a Federal or Indian lease to which this part applies is subject to royalty.</P> <P>(2) When oil is used on, or for the benefit of, the lease at a production facility handling production from more than one lease with the approval of the MMS or BLM, as appropriate, or at a production facility handling unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility may be used royalty-free.</P> <P>(3) Where the terms of any lease are inconsistent with this section, the lease terms shall govern to the extent of that inconsistency.</P> <P>(c) If BLM determines that oil was avoidably lost or wasted from an onshore lease, or that oil was drained from an onshore lease for which compensatory royalty is due, or if MMS determines that oil was avoidably lost or wasted from an offshore lease, then the value of that oil shall be determined in accordance with 30 CFR part 206.</P> <P>(d) If a lessee receives insurance compensation for unavoidably lost oil, royalties are due on the amount of that compensation. This paragraph shall not apply to compensation through self-insurance.</P> <P>(e)(1) In those instances where the lessee of any lease committed to a federally approved unitization or communitization agreement does not actually take the proportionate share of the agreement production attributable to its lease under the terms of the agreement, the full share of production attributable to the lease under the terms of the agreement nonetheless is subject to the royalty payment and reporting requirements of this title. Except as provided in paragraph (e)(2) of this section, the value, for royalty purposes, of production attributable to unitized or communitized leases will be determined in accordance with 30 CFR part 206. In applying the requirements of 30 CFR part 206, the circumstances involved in the actual disposition of the portion of the production to which the lessee was entitled but did not take shall be considered as controlling in arriving at the value, for royalty purposes, of that portion as though the person actually selling or disposing of the production were the lessee of the Federal or Indian lease.</P> <P>(2) If a Federal or Indian lessee takes less than its proportionate share of agreement production, upon request of the lessee MMS may authorize a royalty valuation method different from that required by paragraph (e)(1) of this section, but consistent with the purposes of these regulations, for any volumes not taken by the lessee but for which royalties are due.</P> <P>(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate share of production in any month under a unitization or communitization agreement shall be deemed to have taken ratably from all persons actually taking less than their proportionate share of the agreement production for that month.</P> <P>(4) If a lessee takes less than its proportionate share of agreement production for any month but royalties are paid on the full volume of its proportionate share in accordance with the provisions of this section, no additional royalty will be owed for that lease for prior periods when the lessee subsequently takes more than its proportionate share to balance its account or when the lessee is paid a sum of money by the other agreement participants to balance its account.</P> <P>(f) For production from Federal and Indian leases which are committed to federally-approved unitization or communitization agreements, upon request of a lessee MMS may establish the value of production pursuant to a method other than the method required by the regulations in this title if: (1) The proposed method for establishing value is consistent with the requirements of the applicable statutes, lease terms, and agreement terms; (2) persons with an interest in the agreement, including, to the extent practical, royalty interests, are given notice and an opportunity to comment on the proposed valuation method before it is authorized; and (3) to the extent practical, persons with an interest in a Federal or Indian lease committed to the agreement, including royalty interests, must agree to use the proposed method for valuing production from the agreement for royalty purposes.</P> <CITA>[53 FR 1217, Jan. 15, 1988]</CITA> </SECTION> <SECTION> <PRTPAGE P="8"/> <SECTNO>§ 202.101</SECTNO> <SUBJECT>Standards for reporting and paying royalties.</SUBJECT> <P>Oil volumes are to be reported in barrels of clean oil of 42 standard U.S. gallons (231 cubic inches each) at 60 °F. When reporting oil volumes for royalty purposes, corrections must have been made for Basic Sediment and Water (BS&W) and other impurities. Reported American Petroleum Institute (API) oil gravities are to be those determined in accordance with standard industry procedures after correction to 60 °F.</P> <CITA>[53 FR 1217, Jan. 15, 1988]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart D—Federal Gas</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>53 FR 1271, Jan. 15, 1988, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 202.150</SECTNO> <SUBJECT>Royalty on gas.</SUBJECT> <P>(a) Royalties due on gas production from leases subject to the requirements of this subpart, except helium produced from Federal leases, shall be at the rate established by the terms of the lease. Royalty shall be paid in value unless MMS requires payment in kind. When paid in value, the royalty due shall be the value, for royalty purposes, determined pursuant to 30 CFR part 206 of this title multiplied by the royalty rate in the lease.</P> <P>(b)(1) All gas (except gas unavoidably lost or used on, or for the benefit of, the lease, including that gas used off-lease for the benefit of the lease when such off-lease use is permitted by the MMS or BLM, as appropriate) produced from a Federal lease to which this subpart applies is subject to royalty.</P> <P>(2) When gas is used on, or for the benefit of, the lease at a production facility handling production from more than one lease with the approval of MMS or BLM, as appropriate, or at a production facility handling unitized or communitized production, only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility may be used royalty free.</P> <P>(3) Where the terms of any lease are inconsistent with this subpart, the lease terms shall govern to the extent of that inconsistency.</P> <P>(c) If BLM determines that gas was avoidably lost or wasted from an onshore lease, or that gas was drained from an onshore lease for which compensatory royalty is due, or if MMS determines that gas was avoidably lost or wasted from an OCS lease, then the value of that gas shall be determined in accordance with 30 CFR part 206.</P> <P>(d) If a lessee receives insurance compensation for unavoidably lost gas, royalties are due on the amount of that compensation. This paragraph shall not apply to compensation through self-insurance.</P> <P>(e)(1) In those instances where the lessee of any lease committed to a Federally approved unitization or communitization agreement does not actually take the proportionate share of the production attributable to its Federal lease under the terms of the agreement, the full share of production attributable to the lease under the terms of the agreement nonetheless is subject to the royalty payment and reporting requirements of this title. Except as provided in paragraph (e)(2) of this section, the value for royalty purposes of production attributable to unitized or communitized leases will be determined in accordance with 30 CFR part 206. In applying the requirements of 30 CFR part 206, the circumstances involved in the actual disposition of the portion of the production to which the lessee was entitled but did not take shall be considered as controlling in arriving at the value for royalty purposes of that portion, as if the person actually selling or disposing of the production were the lessee of the Federal lease.</P> <P>(2) If a Federal lessee takes less than its proportionate share of agreement production, upon request of the lessee MMS may authorize a royalty valuation method different from that required by paragraph (e)(1) of this section, but consistent with the purpose of these regulations, for any volumes not taken by the lessee but for which royalties are due.</P> <P>(3) For purposes of this subchapter, all persons actually taking volumes in excess of their proportionate share of production in any month under a unitization or communitization agreement shall be deemed to have taken ratably from all persons actually taking less <PRTPAGE P="9"/>than their proportionate share of the agreement production for that month.</P> <P>(4) If a lessee takes less than its proportionate share of agreement production for any month but royalties are paid on the full volume of its proportionate share in accordance with the provisions of this section, no additional royalty will be owed for that lease for prior periods at the time the lessee subsequently takes more than its proportionate share to balance its account or when the lessee is paid a sum of money by the other agreement participants to balance its account.</P> <P>(f) For production from Federal leases which are committed to federally-approved unitization or communitization agreements, upon request of a lessee MMS may establish the value of production pursuant to a method other than the method required by the regulations in this title if: (1) The proposed method for establishing value is consistent with the requirements of the applicable statutes, lease terms and agreement terms; (2) to the extent practical, persons with an interest in the agreement, including royalty interests, are given notice and an opportunity to comment on the proposed valuation method before it is authorized; and (3) to the extent practical, persons with an interest in a Federal lease committed to the agreement, including royalty interests, must agree to use the proposed method for valuing production from the agreement for royalty purposes.</P> <CITA>[53 FR 1271, Jan. 15, 1988, as amended at 64 FR 43513, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 202.151</SECTNO> <SUBJECT>Royalty on processed gas.</SUBJECT> <P>(a)(1) A royalty, as provided in the lease, shall be paid on the value of:</P> <P>(i) Any condensate recovered downstream of the point of royalty settlement without resorting to processing; and</P> <P>(ii) Residue gas and all gas plant products resulting from processing the gas produced from a lease subject to this subpart.</P> <P>(2) MMS shall authorize a processing allowance for the reasonable, actual costs of processing the gas produced from Federal leases. Processing allowances shall be determined in accordance with 30 CFR part 206 subpart D for gas production from Federal leases and 30 CFR part 206 subpart E for gas production from Indian leases.</P> <P>(b) A reasonable amount of residue gas shall be allowed royalty free for operation of the processing plant, but no allowance shall be made for boosting residue gas or other expenses incidental to marketing, except as provided in 30 CFR part 206. In those situations where a processing plant processes gas from more than one lease, only that proportionate share of each lease's residue gas necessary for the operation of the processing plant shall be allowed royalty free.</P> <P>(c) No royalty is due on residue gas, or any gas plant product resulting from processing gas, which is reinjected into a reservoir within the same lease, unit area, or communitized area, when the reinjection is included in a plan of development or operations and the plan has received BLM or MMS approval for onshore or offshore operations, respectively, until such time as they are finally produced from the reservoir for sale or other disposition off-lease.</P> <CITA>[53 FR 1217, Jan. 15, 1988, as amended at 61 FR 5490, Feb. 12, 1996; 64 FR 43513, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 202.152</SECTNO> <SUBJECT>Standards for reporting and paying royalties on gas.</SUBJECT> <P>(a)(1) If you are responsible for reporting production or royalties, you must:</P> <P>(i) Report gas volumes and British thermal unit (Btu) heating values, if applicable, under the same degree of water saturation;</P> <P>(ii) Report gas volumes in units of 1,000 cubic feet (mcf); and</P> <P>(iii) Report gas volumes and Btu heating value at a standard pressure base of 14.73 pounds per square inch absolute (psia) and a standard temperature base of 60 °F.</P> <P>(2) The frequency and method of Btu measurement as set forth in the lessee's contract shall be used to determine Btu heating values for reporting purposes. However, the lessee shall measure the Btu value at least semiannually by recognized standard industry testing methods even if the lessee's contract provides for less frequent measurement.<PRTPAGE P="10"/> </P> <P>(b)(1) Residue gas and gas plant product volumes shall be reported as specified in this paragraph.</P> <P>(2) Carbon dioxide (CO<E T="52">2</E>), nitrogen (N<E T="52">2</E>), helium (He), residue gas, and any other gas marketed as a separate product shall be reported by using the same standards specified in paragraph (a) of this section.</P> <P>(3) Natural gas liquids (NGL) volumes shall be reported in standard U.S. gallons (231 cubic inches) at 60 °F.</P> <P>(4) Sulfur (S) volumes shall be reported in long tons (2,240 pounds).</P> <CITA>[53 FR 1271, Jan. 15, 1988, as amended at 63 FR 26367, May 12, 1998]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Coal</HD> <SECTION> <SECTNO>§ 202.250</SECTNO> <SUBJECT>Overriding royalty interest.</SUBJECT> <P>The regulations governing overriding royalty interests, production payments, or similar interests created under Federal coal leases are in 43 CFR group 3400.</P> <CITA>[54 FR 1522, Jan. 13, 1989]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Geothermal Resources</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>56 FR 57275, Nov. 8, 1991, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 202.350</SECTNO> <SUBJECT>Scope and definitions.</SUBJECT> <P>(a) This subpart is applicable to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970, as amended (30 U.S.C. 1001 <E T="03">et seq.).</E> </P> <P>(b) The definitions in 30 CFR 206.351 are applicable to this subpart.</P> </SECTION> <SECTION> <SECTNO>§ 202.351</SECTNO> <SUBJECT>Royalties on geothermal resources.</SUBJECT> <P>(a)(1) Royalties on geothermal resources, including byproducts, or on electricity produced using geothermal resources, will be at the royalty rate(s) specified in the lease, unless the Secretary of the Interior temporarily waives, suspends, or reduces that rate(s). Royalties are determined under 30 CFR part 206, subpart H.</P> <P>(2) Fees in lieu of royalties on geothermal resources are prescribed in 30 CFR part 206, subpart H.</P> <P>(3) Except for the amount credited against royalties for in-kind deliveries of electricity to a State or county under § 218.306, you must pay royalties and direct use fees in money.</P> <P>(b)(1) Except as specified in paragraph (b)(2) of this section, royalties or fees are due on—</P> <P>(i) All geothermal resources produced from a lease and that are sold or used by the lessee or are reasonably susceptible to sale or use by the lessee, or</P> <P>(ii) All proceeds derived from the sale of electricity produced using geothermal resources produced from a lease.</P> <P>(2) For purposes of this subparagraph, the terms “Class I lease,” “Class II lease,” and “Class III lease” have the same meanings prescribed in 30 CFR 206.351.</P> <P>(i) For Class I leases, MMS will allow free of royalty—</P> <P>(A) Geothermal resources that are unavoidably lost or reinjected before use on or off the lease, as determined by the Bureau of Land Management (BLM), or that are reasonably necessary to generate plant parasitic electricity or electricity for Federal lease operations; and</P> <P>(B) A reasonable amount of commercially demineralized water necessary for power plant operations or otherwise used on or for the benefit of the lease.</P> <P>(ii) For Class II and Class III leases where the lessee uses geothermal resources for commercial production or generation of electricity, or where geothermal resources are sold at arm's length for the commercial production or generation of electricity, MMS will allow free of royalty or direct use fees geothermal resources that are:</P> <P>(A) Unavoidably lost or reinjected before use on or off the lease, as determined by BLM;</P> <P>(B) Reasonably necessary for the lessee to generate plant parasitic electricity or electricity for Federal lease operations, as approved by BLM; or<PRTPAGE P="11"/> </P> <P>(C) Otherwise used for Federal lease operations related to commercial production or generation of electricity, as approved by BLM.</P> <P>(iii) For Class II and Class III leases where the lessee uses the geothermal resources for a direct use or in a direct use facility, as defined in 30 CFR 206.351, resources that are used to generate electricity for Federal lease operations or that are otherwise used for Federal lease operations are subject to direct use fees, except for geothermal resources that are unavoidably lost or reinjected before use on or off the lease, as determined by BLM.</P> <P>(3) Royalties on byproducts are due at the time the recovered byproduct is used, sold, or otherwise finally disposed of. Byproducts produced and added to stockpiles or inventory do not require payment of royalty until the byproducts are sold, utilized, or otherwise finally disposed of. The MMS may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventories become excessive.</P> <P>(c) If BLM determines that geothermal resources (including byproducts) were avoidably lost or wasted from the lease, or that geothermal resources (including byproducts) were drained from the lease for which compensatory royalty (or compensatory fees in lieu of compensatory royalty) are due, the value of those geothermal resources, or the royalty or fees owed, will be determined under 30 CFR part 206, subpart H.</P> <P>(d) If a lessee receives insurance or other compensation for unavoidably lost geothermal resources (including byproducts), royalties at the rates specified in the lease (or fees in lieu of royalties) are due on the amount of, or as a result of, that compensation. This paragraph will not apply to compensation through self-insurance.</P> <CITA>[72 FR 24458, May 2, 2007]</CITA> </SECTION> <SECTION> <SECTNO>§ 202.352</SECTNO> <SUBJECT>Minimum royalty.</SUBJECT> <P>In no event shall the lessee's annual royalty payments for any producing lease be less than the minimum royalty established by the lease.</P> </SECTION> <SECTION> <SECTNO>§ 202.353</SECTNO> <SUBJECT>Measurement standards for reporting and paying royalties and direct use fees.</SUBJECT> <P>(a) For geothermal resources used to generate electricity, you must report the quantity on which royalty is due on Form MMS-2014 (Report of Sales and Royalty Remittance) as follows:</P> <P>(1) For geothermal resources for which royalty is calculated under § 206.352(a), you must report quantities in:</P> <P>(i) Thousands of pounds to the nearest whole thousand pounds if the contract for the geothermal resources specifies delivery in terms of weight; or</P> <P>(ii) Millions of Btu to the nearest whole million Btu if the sales contract for the geothermal resources specifies delivery in terms of heat or thermal energy.</P> <P>(2) For geothermal resources for which royalty is calculated under § 206.352(b), you must report the quantities in kilowatt-hours to the nearest whole kilowatt-hour.</P> <P>(b) For geothermal resources used in direct use processes, you must report the quantity on which a royalty or direct use fee is due on Form MMS-2014 in:</P> <P>(1) Millions of Btu to the nearest whole million Btu if valuation is in terms of heat or thermal energy used or displaced;</P> <P>(2) Millions of gallons to the nearest million gallons of geothermal fluid produced if valuation or fee calculation is in terms of volume;</P> <P>(3) Millions of pounds to the nearest million pounds of geothermal fluid produced if valuation or fee calculation is in terms of mass; or</P> <P>(4) Any other measurement unit MMS approves for valuation and reporting purposes.</P> <P>(c) For byproducts, you must report the quantity on which royalty is due on Form MMS-2014 consistent with MMS-established reporting standards.</P> <P>(d) For commercially demineralized water, you must report the quantity on which royalty is due on Form MMS-2014 in hundreds of gallons to the nearest hundred gallons.</P> <P>(e) You need not report the quality of geothermal resources, including byproducts, to MMS. However, you must maintain quality measurements for <PRTPAGE P="12"/>audit purposes. Quality measurements include, but are not limited to:</P> <P>(1) Temperatures and chemical analyses for fluid geothermal resources; and</P> <P>(2) Chemical analyses, weight percent, or other purity measurements for byproducts.</P> <CITA>[72 FR 24458, May 2, 2007]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart J—Gas Production From Indian Leases</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>64 FR 43514, Aug. 10, 1999, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 202.550</SECTNO> <SUBJECT>How do I determine the royalty due on gas production?</SUBJECT> <P>If you produce gas from an Indian lease subject to this subpart, you must determine and pay royalties on gas production as specified in this section.</P> <P>(a) <E T="03">Royalty rate.</E> You must calculate your royalty using the royalty rate in the lease.</P> <P>(b) <E T="03">Payment in value or in kind.</E> You must pay royalty in value unless:</P> <P>(1) The Tribal lessor requires payment in kind; or</P> <P>(2) You have a lease on allotted lands and MMS requires payment in kind.</P> <P>(c) <E T="03">Royalty calculation.</E> You must use the following calculations to determine royalty due on the production from or attributable to your lease.</P> <P>(1) When paid in value, the royalty due is the unit value of production for royalty purposes, determined under 30 CFR part 206, multiplied by the volume of production multiplied by the royalty rate in the lease.</P> <P>(2) When paid in kind, the royalty due is the volume of production multiplied by the royalty rate.</P> <P>(d) <E T="03">Reduced royalty rate.</E> The Indian lessor and the Secretary may approve a request for a royalty rate reduction. In your request you must demonstrate economic hardship.</P> <P>(e) <E T="03">Reporting and paying.</E> You must report and pay royalties as provided in part 218 of this title.</P> </SECTION> <SECTION> <SECTNO>§ 202.551</SECTNO> <SUBJECT>How do I determine the volume of production for which I must pay royalty if my lease is not in an approved Federal unit or communitization agreement (AFA)?</SUBJECT> <P>(a) You are liable for royalty on your entitled share of gas production from your Indian lease, except as provided in §§ 202.555, 202.556, and 202.557.</P> <P>(b) You and all other persons paying royalties on the lease must report and pay royalties based on your takes. If another person takes some of your entitled share but does not pay the royalties owed, you are liable for those royalties.</P> <P>(c) You and all other persons paying royalties on the lease may ask MMS for permission to report and pay royalties based on your entitlements. In that event, MMS will provide valuation instructions consistent with this part and part 206 of this title.</P> </SECTION> <SECTION> <SECTNO>§ 202.552</SECTNO> <SUBJECT>How do I determine how much royalty I must pay if my lease is in an approved Federal unit or communitization agreement (AFA)?</SUBJECT> <P>You must pay royalties each month on production allocated to your lease under the terms of an AFA. To determine the volume and the value of your production, you must follow these three steps:</P> <P>(a) You must determine the volume of your entitled share of production allocated to your lease under the terms of an AFA. This may include production from more than one AFA.</P> <P>(b) You must value the production you take using 30 CFR part 206. If you take more than your entitled share of production, see § 202.553 for information on how to value this production. If you take less than your entitled share of production, see § 202.554 for information on how to value production you are entitled to but do not take.</P> </SECTION> <SECTION> <SECTNO>§ 202.553</SECTNO> <SUBJECT>How do I value my production if I take more than my entitled share?</SUBJECT> <P>If you take more than your entitled share of production from a lease in an AFA for any month, you must determine the weighted-average value of all of the production that you take using the procedures in 30 CFR part 206, and use that value for your entitled share of production.</P> </SECTION> <SECTION> <PRTPAGE P="13"/> <SECTNO>§ 202.554</SECTNO> <SUBJECT>How do I value my production that I do not take if I take less than my entitled share?</SUBJECT> <P>If you take none or only part of your entitled production from a lease in an AFA for any month, use this section to value the production that you are entitled to but do not take.</P> <P>(a) If you take a significant volume of production from your lease during the month, you must determine the weighted average value of the production that you take using 30 CFR part 206, and use that value for the production that you do not take.</P> <P>(b) If you do not take a significant volume of production from your lease during the month, you must use paragraph (c) or (d) of this section, whichever applies.</P> <P>(c) In a month where you do not take production or take an insignificant volume, and if you would have used § 206.172(b) to value the production if you had taken it, you must determine the value of production not taken for that month under § 206.172(b) as if you had taken it.</P> <P>(d) If you take none of your entitled share of production from a lease in an AFA, and if that production cannot be valued under § 206.172(b), then you must determine the value of the production that you do not take using the first of the following methods that applies:</P> <P>(1) The weighted average of the value of your production (under 30 CFR part 206) in that month from other leases in the same AFA.</P> <P>(2) The weighted average of the value of your production (under 30 CFR part 206) in that month from other leases in the same field or area.</P> <P>(3) The weighted average of the value of your production (under 30 CFR part 206) during the previous month for production from leases in the same AFA.</P> <P>(4) The weighted average of the value of your production (under 30 CFR part 206) during the previous month for production from other leases in the same field or area.</P> <P>(5) The latest major portion value that you received from MMS calculated under 30 CFR 206.174 for the same MMS-designated area.</P> <P>(e) You may take less than your entitled share of AFA production for any month, but pay royalties on the full volume of your entitled share under this section. If you do, you will owe no additional royalty for that lease for that month when you later take more than your entitled share to balance your account. The provisions of this paragraph (e) also apply when the other AFA participants pay you money to balance your account.</P> </SECTION> <SECTION> <SECTNO>§ 202.555</SECTNO> <SUBJECT>What portion of the gas that I produce is subject to royalty?</SUBJECT> <P>(a) All gas produced from or allocated to your Indian lease is subject to royalty except the following:</P> <P>(1) Gas that is unavoidably lost.</P> <P>(2) Gas that is used on, or for the benefit of, the lease.</P> <P>(3) Gas that is used off-lease for the benefit of the lease when the Bureau of Land Management (BLM) approves such off-lease use.</P> <P>(4) Gas used as plant fuel as provided in 30 CFR 206.179(e).</P> <P>(b) You may use royalty-free only that proportionate share of each lease's production (actual or allocated) necessary to operate the production facility when you use gas for one of the following purposes:</P> <P>(1) On, or for the benefit of, the lease at a production facility handling production from more than one lease with BLM's approval.</P> <P>(2) At a production facility handling unitized or communitized production.</P> <P>(c) If the terms of your lease are inconsistent with this subpart, your lease terms will govern to the extent of that inconsistency.</P> </SECTION> <SECTION> <SECTNO>§ 202.556</SECTNO> <SUBJECT>How do I determine the value of avoidably lost, wasted, or drained gas?</SUBJECT> <P>If BLM determines that a volume of gas was avoidably lost or wasted, or a volume of gas was drained from your Indian lease for which compensatory royalty is due, then you must determine the value of that volume of gas under 30 CFR part 206.</P> </SECTION> <SECTION> <SECTNO>§ 202.557</SECTNO> <SUBJECT>Must I pay royalty on insurance compensation for unavoidably lost gas?</SUBJECT> <P>If you receive insurance compensation for unavoidably lost gas, you must pay royalties on the amount of that compensation. This paragraph does not <PRTPAGE P="14"/>apply to compensation through self-insurance.</P> </SECTION> <SECTION> <SECTNO>§ 202.558</SECTNO> <SUBJECT>What standards do I use to report and pay royalties on gas?</SUBJECT> <P>(a) You must report gas volumes as follows:</P> <P>(1) Report gas volumes and Btu heating values, if applicable, under the same degree of water saturation. Report gas volumes and Btu heating value at a standard pressure base of 14.73 psia and a standard temperature of 60 degrees Fahrenheit. Report gas volumes in units of 1,000 cubic feet (Mcf).</P> <P>(2) You must use the frequency and method of Btu measurement stated in your contract to determine Btu heating values for reporting purposes. However, you must measure the Btu value at least semi-annually by recognized standard industry testing methods even if your contract provides for less frequent measurement.</P> <P>(b) You must report residue gas and gas plant product volumes as follows:</P> <P>(1) Report carbon dioxide (CO<E T="52">2</E>), nitrogen (N<E T="52">2</E>), helium (He), residue gas, and any gas marketed as a separate product by using the same standards specified in paragraph (a) of this section.</P> <P>(2) Report natural gas liquid (NGL) volumes in standard U.S. gallons (231 cubic inches) at 60 degrees F.</P> <P>(3) Report sulfur (S) volumes in long tons (2,240 pounds).</P> </SECTION> </SUBPART> </PART> <PART> <EAR>Pt. 203</EAR> <HD SOURCE="HED">PART 203—RELIEF OR REDUCTION IN ROYALTY RATES</HD> <CONTENTS> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECHD>Sec.</SECHD> <SECTNO>203.0</SECTNO> <SUBJECT>What definitions apply to this part?</SUBJECT> <SECTNO>203.1</SECTNO> <SUBJECT>What is MMS's authority to grant royalty relief?</SUBJECT> <SECTNO>203.2</SECTNO> <SUBJECT>How can I get royalty relief?</SUBJECT> <SECTNO>203.3</SECTNO> <SUBJECT>Why must I pay a fee to request royalty relief?</SUBJECT> <SECTNO>203.4</SECTNO> <SUBJECT>How do the provisions in this part apply to different types of leases and projects?</SUBJECT> <SECTNO>203.5</SECTNO> <SUBJECT>What is MMS's authority to collect information?</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—OCS Oil, Gas, and Sulfur General</HD> <SUBJGRP> <HD SOURCE="HED">Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep Water Royalty Relief</HD> <SECTNO>203.40</SECTNO> <SUBJECT>Which leases are eligible for royalty relief as a result of drilling deep wells?</SUBJECT> <SECTNO>203.41</SECTNO> <SUBJECT>If I have a qualified well, what royalty relief will my lease earn?</SUBJECT> <SECTNO>203.42</SECTNO> <SUBJECT>To which production do I apply the royalty suspension volume earned from qualified wells on my lease?</SUBJECT> <SECTNO>203.43</SECTNO> <SUBJECT>What administrative steps must I take to use the royalty suspension volume?</SUBJECT> <SECTNO>203.44</SECTNO> <SUBJECT>If I drill a certified unsuccessful well, what royalty relief will my lease earn?</SUBJECT> <SECTNO>203.45</SECTNO> <SUBJECT>To which production do I apply the royalty suspension supplements from drilling one or two certified unsuccessful wells on my lease?</SUBJECT> <SECTNO>203.46</SECTNO> <SUBJECT>What administrative steps do I take to obtain and use the royalty suspension supplement?</SUBJECT> <SECTNO>203.47</SECTNO> <SUBJECT>Do I keep royalty relief if prices rise significantly?</SUBJECT> <SECTNO>203.48</SECTNO> <SUBJECT>May I substitute the deep gas drilling provisions in § 203.0 and §§ 203.40 through 203.47 for the deep gas royalty relief provided in my lease terms?</SUBJECT> </SUBJGRP> <SUBJGRP> <HD SOURCE="HED">Royalty Relief for end-of-life Leases</HD> <SECTNO>203.50</SECTNO> <SUBJECT>Who may apply for end-of-life royalty relief?</SUBJECT> <SECTNO>203.51</SECTNO> <SUBJECT>How do I apply for end-of-life royalty relief?</SUBJECT> <SECTNO>203.52</SECTNO> <SUBJECT>What criteria must I meet to get relief?</SUBJECT> <SECTNO>203.53</SECTNO> <SUBJECT>What relief will MMS grant?</SUBJECT> <SECTNO>203.54</SECTNO> <SUBJECT>How does my relief arrangement for an oil and gas lease operate if prices rise sharply?</SUBJECT> <SECTNO>203.55</SECTNO> <SUBJECT>Under what conditions can my end-of-life royalty relief arrangement for an oil and gas lease be ended?</SUBJECT> <SECTNO>203.56</SECTNO> <SUBJECT>Does relief transfer when a lease is assigned?</SUBJECT> </SUBJGRP> <SUBJGRP> <HD SOURCE="HED">Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep Water Leases</HD> <SECTNO>203.60</SECTNO> <SUBJECT>Who may apply for deep water royalty relief?</SUBJECT> <SECTNO>203.61</SECTNO> <SUBJECT>How do I assess my chances for getting relief?</SUBJECT> <SECTNO>203.62</SECTNO> <SUBJECT>How do I apply for relief?</SUBJECT> <SECTNO>203.63</SECTNO> <SUBJECT>Does my application have to include all leases in the field?</SUBJECT> <SECTNO>203.64</SECTNO> <SUBJECT>How many applications may I file on a field or a development project?</SUBJECT> <SECTNO>203.65</SECTNO> <SUBJECT>How long will MMS take to evaluate my application?</SUBJECT> <SECTNO>203.66</SECTNO> <SUBJECT>What happens if MMS does not act in the time allowed?<PRTPAGE P="15"/> </SUBJECT> <SECTNO>203.67</SECTNO> <SUBJECT>What economic criteria must I meet to get royalty relief on an authorized field or project?</SUBJECT> <SECTNO>203.68</SECTNO> <SUBJECT>What pre-application costs will MMS consider in determining economic viability?</SUBJECT> <SECTNO>203.69</SECTNO> <SUBJECT>If my application is approved, what royalty relief will I receive?</SUBJECT> <SECTNO>203.70</SECTNO> <SUBJECT>What information must I provide after MMS approves relief?</SUBJECT> <SECTNO>203.71</SECTNO> <SUBJECT>How does MMS allocate a field's suspension volume between my lease and other leases on my field?</SUBJECT> <SECTNO>203.72</SECTNO> <SUBJECT>Can my lease receive more than one suspension volume?</SUBJECT> <SECTNO>203.73</SECTNO> <SUBJECT>How do suspension volumes apply to natural gas?</SUBJECT> <SECTNO>203.74</SECTNO> <SUBJECT>When will MMS reconsider its determination?</SUBJECT> <SECTNO>203.75</SECTNO> <SUBJECT>What risk do I run if I request a redetermination?</SUBJECT> <SECTNO>203.76</SECTNO> <SUBJECT>When might MMS withdraw or reduce the approved size of my relief?</SUBJECT> <SECTNO>203.77</SECTNO> <SUBJECT>May I voluntarily give up relief if conditions change?</SUBJECT> <SECTNO>203.78</SECTNO> <SUBJECT>Do I keep relief if prices rise significantly?</SUBJECT> <SECTNO>203.79</SECTNO> <SUBJECT>How do I appeal MMS's decisions related to Deep Water Royalty Relief?</SUBJECT> <SECTNO>203.80</SECTNO> <SUBJECT>When can I get royalty relief if I am not eligible for end-of-life or deep water royalty relief?</SUBJECT> </SUBJGRP> <SUBJGRP> <HD SOURCE="HED">Required Reports</HD> <SECTNO>203.81</SECTNO> <SUBJECT>What supplemental reports do royalty-relief applications require?</SUBJECT> <SECTNO>203.82</SECTNO> <SUBJECT>What is MMS's authority to collect this information?</SUBJECT> <SECTNO>203.83</SECTNO> <SUBJECT>What is in an administrative information report?</SUBJECT> <SECTNO>203.84</SECTNO> <SUBJECT>What is in a net revenue and relief justification report?</SUBJECT> <SECTNO>203.85</SECTNO> <SUBJECT>What is in an economic viability and relief justification report?</SUBJECT> <SECTNO>203.86</SECTNO> <SUBJECT>What is in a G&G report?</SUBJECT> <SECTNO>203.87</SECTNO> <SUBJECT>What is in an engineering report?</SUBJECT> <SECTNO>203.88</SECTNO> <SUBJECT>What is in a production report?</SUBJECT> <SECTNO>203.89</SECTNO> <SUBJECT>What is in a deep water cost report?</SUBJECT> <SECTNO>203.90</SECTNO> <SUBJECT>What is in a fabricator's confirmation report?</SUBJECT> <SECTNO>203.91</SECTNO> <SUBJECT>What is in a post-production development report?</SUBJECT> </SUBJGRP> </SUBPART> <SUBPART> <RESERVED>Subpart C—Federal and Indian Oil [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Federal and Indian Gas [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Coal</HD> <SECTNO>203.250</SECTNO> <SUBJECT>Advance royalty.</SUBJECT> <SECTNO>203.251</SECTNO> <SUBJECT>Reduction in royalty rate or rental.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart H—Geothermal Resources [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>25 U.S.C. 396 <E T="03">et seq.</E>; 25 U.S.C. 396a <E T="03">et seq.</E>; 25 U.S.C. 2101 <E T="03">et seq.</E>; 30 U.S.C. 181 <E T="03">et seq.</E>; 30 U.S.C. 351 <E T="03">et seq.</E>; 30 U.S.C. 1001 <E T="03">et seq.</E>; 30 U.S.C. 1701 <E T="03">et seq.</E>; 31 U.S.C. 9701; 43 U.S.C. 1301 <E T="03">et seq.</E>; 43 U.S.C. 1331 <E T="03">et seq.</E>; and 43 U.S.C. 1801 <E T="03">et seq.</E> </P> </AUTH> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>63 FR 2616, Jan. 16, 1998, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 203.0</SECTNO> <SUBJECT>What definitions apply to this part?</SUBJECT> <P> <E T="03">Authorized field</E> means a field:</P> <P>(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;</P> <P>(2) That includes one or more pre-Act leases; and</P> <P>(3) From which no current pre-Act lease produced, other than test production, before November 28, 1995.</P> <P> <E T="03">Certified unsuccessful well</E> means an original well, or a sidetrack with a sidetrack measured depth of at least 10,000 feet, on your lease that:</P> <P>(1) You begin drilling on or after March 26, 2003, and before May 3, 2009, and before your lease produces gas or oil from a deep well with a perforated interval the top of which is at least 18,000 feet true vertical depth below the datum at mean sea level (TVD SS);</P> <P>(2) 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;</P> <P>(3) Fails to meet the producibility requirements of 30 CFR part 250, subpart A, and does not produce gas or oil, or the MMS agrees is not commercially producible; and</P> <P>(4) For which you have provided the notices and information in § 203.46.</P> <P> <E T="03">Complete application</E> means an original and two copies of the six reports consisting of the data specified in 30 CFR 203.81, 203.83 and 203.85 through <PRTPAGE P="16"/>203.89, along with one set of digital information, which MMS has reviewed and found complete.</P> <P> <E T="03">Deep well</E> means either an original well or a sidetrack with a perforated interval the top of which is at least 15,000 feet TVD SS. A deep well subsequently re-perforated less than 15,000 feet TVD SS in the same reservoir is still a deep well.</P> <P> <E T="03">Determination</E> means the binding decision by MMS on whether your field qualifies for relief or how large a royalty-suspension volume must be to make the field economically viable.</P> <P> <E T="03">Development project</E> means a project to develop one or more oil or gas reservoirs located on one or more contiguous leases that:</P> <P>(1) Were issued in a sale held after November 28, 2000;</P> <P>(2) Are located in a water depth of at least 200 meters and in the GOM wholly west of 87 degrees, 30 minutes West longitude; and</P> <P>(3) Have had no production (other than test production) before the current application for royalty relief.</P> <P> <E T="03">Draft application</E> means the preliminary set of information and assumptions you submit to seek a nonbinding assessment on whether a field could be expected to qualify for royalty relief.</P> <P> <E T="03">Eligible lease</E> means a lease that:</P> <P>(1) Is issued as part of an OCS lease sale held after November 28, 1995, and before November 28, 2000;</P> <P>(2) Is located in the Gulf of Mexico in water depths of 200 meters or deeper;</P> <P>(3) Lies wholly west of 87 degrees, 30 minutes West longitude; and</P> <P>(4) Is offered subject to a royalty suspension volume.</P> <P> <E T="03">Expansion project</E> means a project you propose in a Development Operations Coordination Document (DOCD) or a Supplement approved by the Secretary of the Interior after November 28, 1995, that will significantly increase the ultimate recovery of resources from one or more reservoirs that have not produced on a pre-Act lease or a lease issued in a sale held after November 28, 2000. A significant increase does not simply extend recovery from reservoirs already in production. For a pre-Act lease, the expansion project must also involve a substantial capital investment (e.g., fixed-leg platform, subsea template and manifold, tension-leg platform, multiple well project, etc.). For a lease issued after November 28, 2000, the expansion project must involve a new well drilled into a reservoir that has not previously produced. In all cases, all leases in an expansion project must be wholly located in a water depth of at least 200 meters and in the GOM wholly west of 87 degrees, 30 minutes West longitude.</P> <P> <E T="03">Fabrication (or start of construction)</E> means evidence of an irreversible commitment to a concept and scale of development. Evidence includes copies of a binding contract between you (as applicant) and a fabrication yard, a letter from a fabricator certifying that continuous construction has begun, and a receipt for the customary down payment.</P> <P> <E T="03">Field</E> means an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same general geological structural feature or stratigraphic trapping condition. Two or more reservoirs may be in a field, separated vertically by intervening impervious strata or laterally by local geologic barriers, or both.</P> <P> <E T="03">Lease</E> means a lease or unit.</P> <P> <E T="03">New production</E> means any production from a current pre-Act lease from which no royalties are due on production, other than test production, before November 28, 1995. Also, it means any additional production resulting from new lease-development activities on a lease issued in a sale after November 28, 2000, or a current pre-Act lease under a DOCD or a Supplement approved by the Secretary of the Interior after November, 28, 1995.</P> <P> <E T="03">Nonbinding assessment</E> means an opinion by MMS of whether your field could qualify for royalty relief. It is based on your draft application and does not entitle the field to relief.</P> <P> <E T="03">Original well</E> means a well that is drilled without utilizing an existing wellbore. An original well includes all sidetracks drilled from the original wellbore before the drilling rig moves off the well location. A bypass from an original well (e.g., drilling around material blocking the hole or to straighten crooked holes) is part of the original well.<PRTPAGE P="17"/> </P> <P> <E T="03">Participating area</E> means that part of the unit area that MMS determines is reasonably proven by drilling and completion of producible wells, geological and geophysical information, and engineering data to be capable of producing hydrocarbons in paying quantities.</P> <P> <E T="03">Performance conditions</E> means minimum conditions you must meet, after we have granted relief and before production begins, to remain qualified for that relief. If you do not meet each one of these performance conditions, we consider it a change in material fact significant enough to invalidate our original evaluation and approval.</P> <P> <E T="03">Pre-Act lease</E> means a lease that:</P> <P>(1) Results from a sale held before November 28, 1995;</P> <P>(2) Is located in the GOM in water depths of 200 meters or deeper; and</P> <P>(3) Lies wholly west of 87 degrees, 30 minutes West longitude.</P> <P> <E T="03">Production</E> means all oil, gas, and other relevant products you save, remove, or sell from a tract or those quantities allocated to your tract under a unitization formula, as measured for the purposes of determining the amount of royalty payable to the United States.</P> <P> <E T="03">Project</E> means any activity that requires at least a permit to drill.</P> <P> <E T="03">Qualified well</E> means a deep well:</P> <P>(1) For which drilling begins on or after March 26, 2003;</P> <P>(2) That produces natural gas (other than test production), including gas associated with oil production, before May 3, 2009; and</P> <P>(3) For which you have met the requirements prescribed in § 203.43.</P> <P> <E T="03">Redetermination</E> means our reconsideration of our determination on royalty relief because you request it after:</P> <P>(1) We have rejected your application;</P> <P>(2) We have granted relief but you want a larger suspension volume;</P> <P>(3) We withdraw approval; or</P> <P>(4) You renounce royalty relief.</P> <P> <E T="03">Renounce</E> means action you take to give up relief after we have granted it and before you start production.</P> <P> <E T="03">Reservoir</E> means an underground accumulation of oil or natural gas, or both, characterized by a single pressure system and segregated from other such accumulations.</P> <P> <E T="03">Royalty suspension (RS) lease</E> means a lease that:</P> <P>(1) Is issued as part of an OCS lease sale held after November 28, 2000;</P> <P>(2) Is in locations or planning areas specified in a particular Notice of OCS Lease Sale offering that lease; and</P> <P>(3) Is offered subject to a royalty suspension specified in a Notice of OCS Lease Sale published in the <E T="04">Federal Register.</E> </P> <P> <E T="03">Royalty suspension supplement</E> means a royalty suspension volume resulting from drilling a certified unsuccessful well that is applied to future natural gas and oil production generated at any drilling depth on, or allocated under an MMS-approved unit agreement to, the same lease.</P> <P> <E T="03">Royalty suspension volume</E> means a volume of production from a lease that is not subject to royalty under the provisions of this part.</P> <P> <E T="03">Sidetrack</E> means, for the purpose of this subpart, a well resulting from drilling an additional hole to a new objective bottom-hole location by leaving a previously drilled hole. A sidetrack also includes drilling a well from a platform slot reclaimed from a previously drilled well or re-entering and deepening a previously drilled well. A bypass from a sidetrack (e.g., drilling around material blocking the hole, or to straighten crooked holes) is part of the sidetrack.</P> <P> <E T="03">Sidetrack measured depth</E> means the actual distance or length in feet a sidetrack is drilled beginning where it exits a previously drilled hole to the bottom hole of the sidetrack, that is, to its total depth.</P> <P> <E T="03">Sunk costs for an authorized field</E> means the after-tax eligible costs that you (not third parties) incur for exploration, development, and production from the spud date of the first discovery on the field to the date we receive your complete application for royalty relief. The discovery well must be qualified as producible under part 250, subpart A of this title. Sunk costs include the rig mobilization and material costs for the discovery well that you incurred before its spud date.</P> <P> <E T="03">Sunk costs for an expansion or development project</E> means the after-tax eligible costs that you (not third parties) <PRTPAGE P="18"/>incur for only the first well that encounters hydrocarbons in the reservoir(s) included in the application and that meets the producibility requirements under part 250, subpart A of this chapter on each lease participating in the application. Sunk costs include rig mobilization and material costs for the discovery wells that you incurred before their spud dates.</P> <P> <E T="03">Withdraw</E> means action we take on a field that has qualified for relief if you have not met one or more of the performance conditions.</P> <CITA>[63 FR 2616, Jan. 16, 1998, as amended at 67 FR 1872, Jan. 15, 2002; 69 FR 3509, Jan. 26, 2004; 69 FR 24053, Apr. 30, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.1</SECTNO> <SUBJECT>What is MMS's authority to grant royalty relief?</SUBJECT> <P>The Outer Continental Shelf (OCS) Lands Act, 43 U.S.C. 1337, as amended by the OCS Deep Water Royalty Relief Act (DWRRA), Public Law 104-58, authorizes us to grant royalty relief in three situations.</P> <P>(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.</P> <P>(b) Under 43 U.S.C. 1337(a)(3)(B), we may reduce, modify, or eliminate any royalty or net profit share to promote development, increase production, or encourage production of marginal resources on certain leases or categories of leases. This authority is restricted to leases in the Gulf of Mexico (GOM) that are west of 87 degrees, 30 minutes West longitude.</P> <P>(c) Under 43 U.S.C. 1337(a)(3)(C), we may suspend royalties for designated volumes of new production from any lease if:</P> <P>(1) Your lease is in deep water (water at least 200 meters deep);</P> <P>(2) Your lease is in designated areas of the GOM (west of 87 degrees, 30 minutes West longitude);</P> <P>(3) Your lease was acquired in a lease sale held before the DWRRA (before November 28, 1995);</P> <P>(4) We find that your new production would not be economic without royalty relief; and</P> <P>(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.</P> </SECTION> <SECTION> <SECTNO>§ 203.2</SECTNO> <SUBJECT>How can I get royalty relief?</SUBJECT> <P>We may reduce or suspend royalties for Outer Continental Shelf (OCS) leases or projects that meet the criteria in the following table.</P> <GPOTABLE CDEF="s75,r75,r75" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1">If you have a lease . . .</CHED> <CHED H="1">And if you . . .</CHED> <CHED H="1">Then we may grant you . . .</CHED> </BOXHD> <ROW> <ENT I="01">(a) With earnings that cannot sustain production (<E T="03">i.e.</E>, <E T="03">End-of-life lease</E>)</ENT> <ENT O="xl">Would abandon otherwise potentially recoverable resources but seek to increase production by operating beyond the point at which the lease is economic under the existing royalty rate.</ENT> <ENT>A reduced royalty rate on current monthly production and a higher royalty rate on additional monthly production. (See §§ 203.50 through 203.56.)</ENT> </ROW> <ROW> <ENT I="01" O="xl">(b) Located in a designated GOM deep water area, and acquired in a lease sale before November 28, 1995, or after November 28, 2000, and you propose in a DOCD or supplement to expand production significantly.</ENT> <ENT>Are producing and seek to increase ultimate resource recovery from one or more reservoirs not previously or currently producing on the field or lease, not simply extend recovery of reservoirs that already produced. (<E T="03">Expansion project</E>)</ENT> <ENT>A royalty suspension for additional production large enough to make the project economic. (See §§ 203.60 through 203.79.)</ENT> </ROW> <ROW> <ENT I="01">(c) Located in a designated GOM deep water area and acquired in a lease sale held before November 28, 1995 (<E T="03">Pre-Act lease</E>)</ENT> <ENT>Are on a field from which no current pre-Act lease produced (other than test production) before November 28, 1995 (<E T="03">Authorized field)</E> </ENT> <ENT>A royalty suspension for a minimum production volume plus any additional volume needed to make the field economic. (See §§ 203.60 through 203.79.)</ENT> </ROW> <ROW> <ENT I="01">(d) Located in a designated GOM deep water area and acquired in a lease sale held after November 28, 2000</ENT> <ENT>Have not produced and can demonstrate that the suspension volume, if any, in your lease is not enough to make development economic (<E T="03">Development project</E>)</ENT> <ENT>A royalty suspension for a minimum production volume plus any additional volume needed to make your project economic. (See §§ 203.60 through 203.79.)</ENT> </ROW> <ROW> <ENT I="01">(e) Where royalty relief would recover significant additional resources or, in certain areas of the GOM, would enable development</ENT> <ENT>Are not eligible to apply for end-of-life or deep water royalty relief, but show us you meet certain elligibility conditions</ENT> <ENT>A royalty modification in size, duration, or form that makes your lease or project economic. (See § 203.80.)</ENT> </ROW> </GPOTABLE> <PRTPAGE P="19"/> <CITA>[67 FR 1872, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.3</SECTNO> <SUBJECT>Why must I pay a fee to request royalty relief?</SUBJECT> <P>(a) When you submit an application or ask for a preview assessment, you must include a fee to reimburse us for our costs of processing your application or assessment. Federal policy and law require us to recover the cost of services that confer special benefits to identifiable non-Federal recipients. The Independent Offices Appropriation Act (31 U.S.C. 9701), Office of Management and Budget Circular A-25, and the Omnibus Appropriations Bill (Pub. L. 104-133, 110 Stat. 1321, April 26, 1996) authorize us to collect these fees.</P> <P>(b) 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.</P> </SECTION> <SECTION> <SECTNO>§ 203.4</SECTNO> <SUBJECT>How do the provisions in this part apply to different types of leases and projects?</SUBJECT> <P>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.</P> <P>(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.</P> <GPOTABLE CDEF="i1,s75,7C,11C,7C,11C" COLS="5" OPTS="L2"> <BOXHD> <CHED H="1">Information elements</CHED> <CHED H="1">End-of-life lease</CHED> <CHED H="1">Deep water</CHED> <CHED H="2">Expansion project</CHED> <CHED H="2">Pre-act lease</CHED> <CHED H="2">Development project</CHED> </BOXHD> <ROW> <ENT I="01">(1) Administrative information report</ENT> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(2) Net revenue and relief justification report (prescribed format)</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(3) Economic viability and relief justification report (Royalty Suspension Viability Program (RSVP) model inputs justified with Geological and Geophysical (G&G), Engineering, Production, & Cost reports)</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(4) G&G report</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(5) Engineering report</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(6) Production report</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(7) Deep water cost report</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> </GPOTABLE> <P>(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.</P> <GPOTABLE CDEF="s75,7C,11C,7C,11C" COLS="5" OPTS="L2"> <BOXHD> <CHED H="1">Confirmation elements</CHED> <CHED H="1">End-of-life lease</CHED> <CHED H="1">Deep water</CHED> <CHED H="2">Expansion project</CHED> <CHED H="2">Pre-act lease</CHED> <CHED H="2">Development project</CHED> </BOXHD> <ROW> <ENT I="01">(1) Fabricator's confirmation report</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(2) Post-production development report approved by an independent certified public accountant (CPA)</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> </GPOTABLE> <P>(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.<PRTPAGE P="20"/> </P> <GPOTABLE CDEF="s75,7C,11C,7C,11C" COLS="5" OPTS="L2"> <BOXHD> <CHED H="1">Approval conditions</CHED> <CHED H="1">End-of-life lease</CHED> <CHED H="1">Deep water</CHED> <CHED H="2">Expansion</CHED> <CHED H="2">Pre-act lease</CHED> <CHED H="2">Development project</CHED> </BOXHD> <ROW> <ENT I="01">(1) At least 12 of the last 15 months have the required level of production</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(2) Already producing</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(3)A producible well into a reservoir that has not produced before</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(4) Royalties for qualifying months exceed 75% of net revenue (NR)</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(5) Substantial investment on a pre-Act lease (e.g., platform, subsea template)</ENT> </ROW> <ROW> <ENT I="01">(6) Determined to be economic only with relief</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> </GPOTABLE> <P>(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.</P> <GPOTABLE CDEF="s75,7C,11C,7C,11C" COLS="5" OPTS="L2"> <BOXHD> <CHED H="1">Redetermination conditions</CHED> <CHED H="1">End-of-Life lease</CHED> <CHED H="1">Deep water</CHED> <CHED H="2">Expansion project</CHED> <CHED H="2">Pre-act lease</CHED> <CHED H="2">Development project</CHED> </BOXHD> <ROW> <ENT I="01">(1) After 12 months under current rate, criteria same as for approval</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(2) For material change in geologic data, prices, costs, or available technology</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> </GPOTABLE> <P>(e) The following table indicates by an X, and §§ 203.53 and 203.69 describe, the characteristics of approved royalty relief.</P> <GPOTABLE CDEF="s75,7C,11C,7C,11C" COLS="5" OPTS="L2"> <BOXHD> <CHED H="1">Relief rate and volume, subject to certain conditions</CHED> <CHED H="1">End-of-life lease</CHED> <CHED H="1">Deep water</CHED> <CHED H="2">Expansion project</CHED> <CHED H="2">Pre-act lease</CHED> <CHED H="2">Development project</CHED> </BOXHD> <ROW> <ENT I="01">(1) One-half pre-application effective lease rate on the qualifying amount, 1.5 times pre-application effective lease rate on additional production up to twice the qualifying amount, and the pre-application effective lease rate for any larger volumes</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(2) Qualifying amount is the average monthly production for 12 qualifying months</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(3) Zero royalty rate on the suspension volume and the original lease rate on additional production</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(4) Suspension volume is at least 17.5, 52.5 or 87.5 million barrels of oil equivalent (MMBOE)</ENT> <ENT/> <ENT/> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(5) Suspension volume is at least the minimum set in the Notice of Sale, the lease, or the regulations</ENT> <ENT/> <ENT>X</ENT> <ENT/> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(6) Amount needed to become economic</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> </GPOTABLE> <P>(f) The following table indicates by an X, and §§ 203.54 and 203.78 describe, circumstances under which we discontinue your royalty relief.</P> <GPOTABLE CDEF="s75,7C,11C,7C,11C" COLS="5" OPTS="L2"> <BOXHD> <CHED H="1">Full royalty resumes when</CHED> <CHED H="1">End-of-life lease</CHED> <CHED H="1">Deep water</CHED> <CHED H="2">Expansion project</CHED> <CHED H="2">Pre-act lease</CHED> <CHED H="2">Development project</CHED> </BOXHD> <ROW> <ENT I="01">(1) Average NYMEX price for last 12 months is at least 25 percent above the average for the qualifying months</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(2) Average NYMEX price for last calendar year exceeds $28/bbl or $3.50/mcf, escalated by the gross domestic product (GDP) deflator since 1994</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(3) Average prices for designated periods exceed levels we specify in the Notice of Sale or the lease</ENT> <ENT/> <ENT>X</ENT> <ENT/> <ENT>X</ENT> </ROW> </GPOTABLE> <P>(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.<PRTPAGE P="21"/> </P> <GPOTABLE CDEF="s75,7C,11C,7C,11C" COLS="5" OPTS="L2"> <BOXHD> <CHED H="1">Relief withdrawn or reduced</CHED> <CHED H="1">End-of-life lease</CHED> <CHED H="1">Deep water</CHED> <CHED H="2">Expansion project</CHED> <CHED H="2">Pre-act lease</CHED> <CHED H="2">Development project</CHED> </BOXHD> <ROW> <ENT I="01">(1) If recipient requests</ENT> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(2) Lease royalty rate is at the effective rate for 12 consecutive months</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(3) Conditions occur that we specified in the approval letter in individual cases</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(4) Recipient does not submit post-production report that compares expected to actual costs</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(5) Recipient changes development system</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(6) Recipient excessively delays starting fabrication</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(7) Recipient spends less than 80 percent of proposed pre-production costs prior to start of production</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(8) Amount of relief volume is produced</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> </GPOTABLE> <CITA>[67 FR 1873, Jan. 15, 2002, as amended at 69 FR 3509, Jan. 26, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.5</SECTNO> <SUBJECT>What is MMS's authority to collect information?</SUBJECT> <P>The Paperwork Reduction Act of 1995 (PRA) requires us to inform you that MMS 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. OMB approved the information collection requirements in this part 203 under 44 U.S.C. 3501 <E T="03">et seq.</E> in two actions. The information collection requirements in §§ 203.50 through 203.91 are approved under OMB control number 1010-0071, and those in §§ 203.40 through 203.48 are approved under 1010-0153.</P> <CITA>[69 FR 3509, Jan. 26, 2004]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—OCS Oil, Gas, and Sulfur General</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>63 FR 2618, Jan. 16, 1998, unless otherwise noted.</P> </SOURCE> <SUBJGRP> <HD SOURCE="HED">Royalty Relief for Drilling Deep Gas Wells on Leases Not Subject to Deep Water Royalty Relief</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>69 FR 3510, Jan. 26, 2004, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 203.40</SECTNO> <SUBJECT>Which leases are eligible for royalty relief as a result of drilling deep wells?</SUBJECT> <P>Your lease may receive a royalty suspension volume under §§ 203.41 through 203.43, and may receive a royalty suspension supplement under §§ 203.44 through 203.46, if it:</P> <P>(a) Was:</P> <P>(1) In existence on January 1, 2001;</P> <P>(2) Issued in a lease sale held after January 1, 2001, and before April 1, 2004, and either the lessee has exercised the option provided for in § 203.48 or the lease is located partly in water less than 200 meters deep and no deep water royalty relief provisions in statutes or lease terms apply to the lease; or</P> <P>(3) Issued in a lease sale held on or after April 1, 2004, and either the lease terms provide for royalty relief under §§ 203.41 through 203.47 of this part or the lease is located partly in water less than 200 meters deep and no deep water royalty relief provisions in statutes or lease terms apply to the lease;</P> <P>(b) Is located:</P> <P>(1) In the GOM, wholly west of 87 degrees, 30 minutes West longitude;</P> <P>(2) Entirely in water less than 200 meters deep, or partly in water less than 200 meters deep and no deep-water royalty relief provisions in statutes or lease terms apply to the lease; and</P> <P>(c) Has not produced gas or oil from a deep well with a perforated interval the top of which is 18,000 feet TVD SS or deeper that commenced drilling before March 26, 2003.</P> <CITA>[69 FR 3510, Jan. 26, 2004, as amended at 70 FR 22252, Apr. 29, 2005]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.41</SECTNO> <SUBJECT>If I have a qualified well, what royalty relief will my lease earn?</SUBJECT> <P>(a) This paragraph and paragraph (b) of this section apply if your lease has not produced gas or oil from a deep well that commenced drilling before March 26, 2003. Subject to the administrative requirements of § 203.43, the provisions of § 203.44(d), and the price <PRTPAGE P="22"/>conditions in § 203.47, you earn a royalty suspension volume shown in the following table in billions of cubic feet (BCF) or in thousands of cubic feet (MCF) applicable to gas production as prescribed in § 203.42:</P> <GPOTABLE CDEF="s100,r100" COLS="2" OPTS="L2,tp0,i1"> <BOXHD> <CHED H="1">If you have a qualified well that is . . .</CHED> <CHED H="1">Then you earn a royalty suspension volume on this amount of gas production, as prescribed in this section and § 203.42:</CHED> </BOXHD> <ROW> <ENT I="01">(1) An original well with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS</ENT> <ENT>15 BCF.</ENT> </ROW> <ROW> <ENT I="01">(2) A sidetrack with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS</ENT> <ENT>4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 15 BCF.</ENT> </ROW> <ROW> <ENT I="01">(3) An original well with a perforated interval the top of which is 18,000 feet TVD SS or deeper</ENT> <ENT>25 BCF.</ENT> </ROW> <ROW> <ENT I="01">(4) A sidetrack with a perforated interval the top of which is 18,000 feet TVD SS or deeper</ENT> <ENT>4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 25 BCF.</ENT> </ROW> </GPOTABLE> <P>(b) We will suspend royalties on gas volumes produced on or after May 3, 2004, reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease under § 216.53, as and to the extent prescribed in § 203.42. All gas production from qualified wells reported on the OGOR-A, including production that is not subject to royalty (except for production to which a royalty suspension supplement under §§ 203.44 and 203.45 applies), counts toward the lease royalty suspension volume. </P> <EXAMPLE> <HD SOURCE="HED">Example 1.</HD> <P>If you have a qualified well that is an original well with a perforated interval the top of which is 16,000 feet TVD SS, you earn a royalty suspension volume of 15 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42. However, if the top of the perforated interval is 18,500 feet TVD SS, the royalty suspension volume is 25 BCF.</P> </EXAMPLE> <EXAMPLE> <HD SOURCE="HED">Example 2.</HD> <P>If you have a qualified well that is a sidetrack with a perforated interval the top of which is 16,000 feet TVD SS, that has a sidetrack measured depth of 6,789 feet, we round the distance to 6,800 feet and you earn a royalty suspension volume of 8.08 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42.</P> </EXAMPLE> <EXAMPLE> <HD SOURCE="HED">Example 3.</HD> <P>If you have a qualified well that is a sidetrack with a perforated interval the top of which is 16,000 feet TVD SS, that has a sidetrack measured depth of 19,500 feet, you earn a royalty suspension volume of 15 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42, even though 4 BCF plus 600 MCF per foot of sidetrack measured depth equals 15.7 BCF.</P> </EXAMPLE> <P>(c) This paragraph and paragraph (d) of this section apply if your lease has produced gas or oil from a deep well with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS (regardless of whether drilling began before or after March 26, 2003), and you subsequently have a qualified well on your lease with a perforated interval the top of which is 18,000 feet TVD or deeper. Subject to the administrative requirements of § 203.43, the provisions of § 203.44(d), and the price conditions in § 203.47, you earn a royalty suspension volume specified in the following table, applicable to gas production as prescribed in § 203.42. This royalty suspension volume is in addition to any royalty suspension volume your lease already may have earned, if any, as a result of a qualified well with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS.</P> <GPOTABLE CDEF="s100,r100" COLS="2" OPTS="L2,tp0,i1"> <BOXHD> <CHED H="1">If your lease has produced gas or oil from a deep well with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS, and you subsequently have a qualified well that is . . .</CHED> <CHED H="1">Then, you earn a royalty suspension volume on this amount of gas production, as prescribed in this section and § 203.42</CHED> </BOXHD> <ROW> <ENT I="01">(1) An original well or a sidetrack with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS</ENT> <ENT>0 BCF.</ENT> </ROW> <ROW> <ENT I="01">(2) An original well with a perforated interval the top of which is 18,000 feet TVD SS or deeper</ENT> <ENT>10 BCF.</ENT> </ROW> <ROW> <ENT I="01">(3) A sidetrack with a perforated interval the top of which is 18,000 feet TVD SS or deeper</ENT> <ENT>4 BCF plus 600 MCF times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 10 BCF.</ENT> </ROW> </GPOTABLE> <P>(d) We will suspend royalties on gas volumes produced on or after May 3, 2004, reported on the Oil and Gas Operations Report, Part A (OGOR-A) for <PRTPAGE P="23"/>your lease under § 216.53, as and to the extent prescribed in § 203.42. All gas production from qualified wells reported on the OGOR-A, including production that is not subject to royalty (except for production to which a royalty suspension supplement under §§ 203.44 and 203.45 applies), counts toward the lease royalty suspension volume. </P> <EXAMPLE> <HD SOURCE="HED">Example 1.</HD> <P>If you have drilled and produced a well with a perforated interval the top of which is 16,000 feet TVD SS before March 26, 2003 (and therefore, it is not a qualified well and has earned no royalty suspension volume) and later drill:</P> <P>(i) A well with a perforated interval the top of which is 17,000 feet TVD SS, you earn no royalty suspension volume.</P> <P>(ii) A qualified well that is an original well with a perforated interval the top of which is 19,000 feet TVD SS, you earn a royalty suspension volume of 10 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42.</P> <P>(iii) A qualified 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, you earn a royalty suspension volume of 8.2 BCF of gas production from qualified wells on your lease, as prescribed in § 203.42.</P> </EXAMPLE> <EXAMPLE> <HD SOURCE="HED">Example 2.</HD> <P>If you have a qualified well (<E T="03">i.e.</E>, drilled after March 26, 2003) 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 royalty suspension volume for your lease from 15 BCF to 25 BCF, as prescribed in § 203.42.</P> </EXAMPLE> <EXAMPLE> <HD SOURCE="HED">Example 3.</HD> <P>If you have a qualified well (<E T="03">i.e.</E>, drilled after March 26, 2003) that is a sidetrack with a perforated interval the top of which is 16,000 feet TVD SS, that has 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, that has a sidetrack measured depth of 8,000 feet, we increase the total royalty suspension volume for your lease from 6.4 BCF to 15.2 BCF, as prescribed in § 203.42. The difference of 8.8 BCF represents the royalty suspension volume earned by the second sidetrack.</P> </EXAMPLE> <P>(e) After your lease has produced gas or oil from a deep well with a perforated interval the top of which is 18,000 feet TVD SS or deeper, your lease cannot earn a royalty suspension volume as a result of drilling any subsequent qualified wells.</P> <P>(f) The royalty suspension volume determined under this section for the first qualified well on your lease (whether an original well or a sidetrack) establishes the total royalty suspension volume available for that drilling depth interval on your lease, regardless of the number of subsequent qualified wells you drill to that depth interval. </P> <EXAMPLE> <HD SOURCE="HED">Example to paragraph (f):</HD> <P>If your first qualified well is a sidetrack with a perforated interval the top of which is 16,000 feet TVD SS and earns a royalty suspension volume of 12.5 BCF, and you later drill a qualified original well to 17,000 feet TVD SS, the royalty suspension volume for your lease remains at 12.5 BCF and does not increase to 15 BCF. However, under paragraph (b) of this section, if you subsequently drill a qualified well to another depth interval 18,000 feet or greater TVD SS, you may earn an additional royalty suspension volume.</P> </EXAMPLE> <P>(g) If a qualified well on your lease is within a unitized portion of your lease, the royalty suspension volume earned by that well under this section applies only to your lease and not to other leases within the unit.</P> <P>(h) If your qualified well is a directional well (either an original well or a sidetrack) drilled across a lease line, the lease with the perforated interval that initially produces earns the royalty suspension volume. However, if the perforated interval crosses a lease line, the lease where the surface of the well is located earns the royalty suspension volume.</P> <P>(i) Any royalty suspension volume earned under this section is in addition to any royalty suspension supplement for your lease under § 203.44 that results from a different wellbore.</P> <P>(j) If your lease earns a royalty suspension volume under this section and later produces from a deep well that is not a qualified well, the royalty suspension volume is not forfeited or terminated. However, you may not apply the royalty suspension volume under this section to production from the deep well that is not a qualified well, even if it begins producing after your first qualified well.</P> <P>(k) You owe minimum royalties or rentals in accordance with your lease terms notwithstanding any royalty <PRTPAGE P="24"/>suspension volumes allowed under paragraphs (a) and (b) of this section.</P> <CITA>[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24053, Apr. 30, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.42</SECTNO> <SUBJECT>To which production do I apply the royalty suspension volume earned from qualified wells on my lease?</SUBJECT> <P>(a) This paragraph applies to any lease that is not within an MMS-approved unit. Subject to the requirements of §§ 203.40, 203.41, 203.43, 203.44, and 203.47, you must apply the royalty suspension volumes prescribed in § 203.41 to the earliest gas production:</P> <P>(1) Occurring on and after the later of May 3, 2004, or the date that the first qualified well that earns your lease the royalty suspension volume begins production (other than test production);</P> <P>(2) From all qualified wells, regardless of their depth, on your lease for which you have met the requirements in § 203.43, up to the aggregate royalty suspension volume earned by your lease. </P> <EXAMPLE> <HD SOURCE="HED">Example to paragraph (a):</HD> <P>You began drilling an original well that was a qualified well with a perforated interval the top of which is 18,200 feet TVD SS on May 1, 2003 and it began producing on September 1, 2003. You subsequently drilled two more original wells that are qualified wells with a perforated interval the tops of which are 16,600 feet TVD SS. The first well earned a royalty suspension volume of 25 BCF. You must apply the royalty suspension volume each month beginning on March 1, 2004 to production from all three wells until the 25 BCF royalty suspension volume is fully utilized.</P> </EXAMPLE> <P>(b) This paragraph applies to any lease all or part of which is within an MMS-approved unit. If your lease has a qualified well, a share of the production from all the qualified wells in the unit participating area will be allocated to your lease each month according to the participating area percentages. Subject to the requirements of §§ 203.40, 203.41, 203.43, 203.44, and 203.47, you must apply the royalty suspension volume to the earliest gas production occurring on and after the later of May 3, 2004, or the date that the first qualified well that earns your lease the royalty suspension volume begins production (other than test production):</P> <P>(1) From all qualified wells on the non-unitized area of your lease and</P> <P>(2) Allocated to your lease from qualified wells on unitized areas of your lease and other leases in the unit under an MMS-approved unit agreement. That allocated share does not increase the royalty suspension volume 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. </P> <EXAMPLE> <HD SOURCE="HED">Example to paragraph (b):</HD> <P>The east half of your lease A is unitized with all of lease B. There is one qualified well on the non-unitized portion of lease A, one qualified well on the unitized portion of lease A and a qualified well on lease B. The participating area percentages allocate 32 percent of production from both of the unit qualified wells to lease A and 68 percent to lease B. If the non-unitized qualified well on lease A produces 12,000 MCF and the unitized qualified well on lease A produces 15,000 MCF, and the qualified well on lease B produces 10,000 MCF, then the production volume from and allocated to lease A to which the lease A royalty suspension volume applies is 20,000 MCF [12,000 + (15,000 + 10,000)(32 percent)]. The production volume allocated to lease B to which the lease B royalty suspension volume applies is 17,000 MCF [(15,000 + 10,000)(68 percent)].</P> </EXAMPLE> <P>(c) Unused royalty suspension volume transfers to a successor lessee and expires with the lease.</P> <P>(d) You may not apply the royalty suspension volume allowed under § 203.41:</P> <P>(1) 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;</P> <P>(2) To production from a deep well that commenced drilling before March 26, 2003; or</P> <P>(3) To production from a deep well on any other lease, except as provided in paragraph (b) of this section.</P> <P>(e) 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 royalty suspension volume allowed under § 203.41. For the month in which cumulative production reaches this royalty suspension volume, you <PRTPAGE P="25"/>owe royalties on the portion of gas production that exceeds the royalty suspension volume remaining at the beginning of that month.</P> <P>(f) No royalty suspension volume may be applied to any liquid hydrocarbon (oil and condensate) volumes.</P> <CITA>[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.43</SECTNO> <SUBJECT>What administrative steps must I take to use the royalty suspension volume?</SUBJECT> <P>(a) You must notify, in writing, the MMS Regional Supervisor for Production and Development of your intent to begin drilling operations on all deep wells; and</P> <P>(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:</P> <P>(1) Provide written notification to the MMS Regional Supervisor for Production and Development that production has begun; and</P> <P>(2) Request confirmation of the size of the royalty suspension volume earned by your lease.</P> <P>(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.</P> <P>(d) If you produced from a qualified well before May 3, 2004, you must provide the information in paragraph (b) of this section no later than August 3, 2004.</P> <P>(e) If you cannot produce from a well that otherwise meets the criteria for a qualified well before May 3, 2009, 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, provided you demonstrate that:</P> <P>(1) The delay occurred after reaching total depth in your well;</P> <P>(2) Production (other than test production) was expected to begin before March 1, 2009; and</P> <P>(3) The delay in beginning production is for reasons beyond your control, including but not limited to adverse weather and unavoidable accidents.</P> <CITA>[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.44</SECTNO> <SUBJECT>If I drill a certified unsuccessful well, what royalty relief will my lease earn?</SUBJECT> <P>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.</P> <P>(a) If you drill a certified unsuccessful well and you satisfy the administrative requirements of § 203.46 and subject to the price conditions in § 203.47, you earn a royalty suspension supplement shown in the following table (in billions of cubic feet of gas equivalent (BCFE) or in thousands of cubic feet of gas equivalent (MCFE)) applicable to oil and gas production as prescribed in § 203.45:</P> <GPOTABLE CDEF="s100,r100" COLS="2" OPTS="L2,tp0,i1"> <BOXHD> <CHED H="1">If you have a certified unsuccessful well that is . . .</CHED> <CHED H="1">Then, you earn a royalty suspension supplement on this volume of oil and gas production as prescribed in this section and § 203.45:</CHED> </BOXHD> <ROW> <ENT I="01">(1) An original well and your lease has not produced gas or oil from a deep well</ENT> <ENT>5 BCFE.</ENT> </ROW> <ROW> <ENT I="01">(2) A sidetrack (with a sidetrack measured depth of at least 10,000 feet) and your lease has not produced gas or oil from a deep well</ENT> <ENT>0.8 BCFE plus 120 MCFE times sidetrack measured depth (rounded to the nearest 100 feet) but no more than 5 BCFE.</ENT> </ROW> <ROW> <ENT I="01">(3) An original well or a sidetrack (with a sidetrack measured depth of at least 10,000 feet) and your lease has produced gas or oil from a deep well with a perforated interval the top of which is from 15,000 to less than 18,000 feet TVD SS</ENT> <ENT>2 BCFE.</ENT> </ROW> </GPOTABLE> <P>(b) We will suspend royalties on oil and gas volumes produced on or after May 3, 2004, reported on the Oil and Gas Operations Report, Part A (OGOR-A) for your lease under § 216.53, as and to the extent prescribed in § 203.45. All oil and gas production reported on the OGOR-A, including production that is <PRTPAGE P="26"/>not subject to royalty (except for production to which a royalty suspension volume under §§ 203.41 and 203.42 applies), counts toward the lease royalty suspension supplement. </P> <EXAMPLE> <HD SOURCE="HED">Example 1.</HD> <P>If you drill a certified unsuccessful well that is an original well to a target 19,000 feet TVD SS, you earn a royalty suspension supplement of 5 BCFE of gas and oil production if your lease has not previously produced from a deep well, or you earn a royalty suspension supplement 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 § 203.45.</P> </EXAMPLE> <EXAMPLE> <HD SOURCE="HED">Example 2.</HD> <P>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, we round the distance to 12,500 feet and you earn a royalty suspension supplement of 2.3 BCFE of gas and oil production as prescribed in § 203.45.</P> </EXAMPLE> <P>(c) The conversion from oil to gas for using the royalty suspension supplement is specified in § 203.73.</P> <P>(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.</P> <P>(1) You may not earn more than one royalty suspension supplement from a single wellbore.</P> <P>(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.</P> <P>(e) If the same wellbore that earns a royalty suspension supplement as a certified unsuccessful well later produces from a perforated interval the top of which is 15,000 feet TVD SS or deeper before May 3, 2009, it will become a qualified well subject to the following conditions:</P> <P>(1) Beginning on the date production starts, you must stop applying the royalty suspension supplement earned by that wellbore to your lease production.</P> <P>(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.</P> <P>(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.</P> <P>(g) You owe minimum royalties or rentals in accordance with your lease terms notwithstanding any royalty suspension supplements under this section.</P> <CITA>[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004; 72 FR 25198, May 4, 2007]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.45</SECTNO> <SUBJECT>To which production do I apply the royalty suspension supplements from drilling one or two certified unsuccessful wells on my lease?</SUBJECT> <P>(a) Subject to the requirements of §§ 203.40, 203.42, 203.44, 203.46 and 203.47, you must apply royalty suspension supplements in § 203.44 to the earliest oil and gas production:</P> <P>(1) Occurring on and after the day you file the information under § 203.46(b),</P> <P>(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.</P> <P>(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. </P> <EXAMPLE> <HD SOURCE="HED">Example to paragraph (b):</HD> <P>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. <PRTPAGE P="27"/>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 3 BCFE of the royalty suspension supplement for gas produced from the qualified well.</P> </EXAMPLE> <P>(c) If you have no current production on which to apply the royalty suspension supplement allowed under § 203.44, your royalty suspension supplement applies to the earliest subsequent production of gas and oil from, or allocated under an MMS-approved unit agreement to, your lease.</P> <P>(d) Unused royalty suspension supplements transfer to a successor lessee and expire with the lease.</P> <P>(e) You may not apply the royalty suspension supplement allowed under § 203.44 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 royalty suspension supplement for your lease to production from the other leases in the unit.</P> <P>(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.</P> </SECTION> <SECTION> <SECTNO>§ 203.46</SECTNO> <SUBJECT>What administrative steps do I take to obtain and use the royalty suspension supplement?</SUBJECT> <P>(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.</P> <P>(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:</P> <P>(1) Information that allows MMS to confirm that you drilled a certified unsuccessful well as defined under § 203.0, including:</P> <P>(i) Well log data, if your original well or sidetrack does not meet the producibility requirements of 30 CFR part 250, subpart A; or</P> <P>(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</P> <P>(2) Information that allows MMS to confirm the size of the royalty suspension supplement for a sidetrack, including sidetrack measured depth and supporting documentation.</P> <P>(c) If you commenced drilling a well that otherwise meets the criteria for a certified unsuccessful well on or after March 26, 2003, and finished it before May 3, 2004, provide the information in paragraph (b) of this section no later than August 3, 2004.</P> <CITA>[69 FR 3510, Jan. 26, 2004, as amended at 69 FR 24054, Apr. 30, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.47</SECTNO> <SUBJECT>Do I keep royalty relief if prices rise significantly?</SUBJECT> <P>(a) You must pay royalties on all gas and oil production for which royalty suspension volume or royalty suspension supplement otherwise would be allowed under §§ 203.40 through 203.46 for any calendar year when the average daily closing NYMEX natural gas price exceeds the threshold of $9.34 per MMBtu, adjusted annually after year 2004 for inflation. The threshold price for any calendar year after 2004 is found 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.</P> <P>(b) You must pay any royalty due under this paragraph, plus late payment interest from the end of the month after the month of production until the date of payment under 30 CFR 218.54, no later than 90 days after the end of the calendar year for which you owe royalty.</P> <P>(c) Production volumes on which you must pay royalty under this section <PRTPAGE P="28"/>count as part of your royalty suspension volumes and royalty suspension supplements.</P> </SECTION> <SECTION> <SECTNO>§ 203.48</SECTNO> <SUBJECT>May I substitute the deep gas drilling provisions in § 203.0 and §§ 203.40 through 203.47 for the deep gas royalty relief provided in my lease terms?</SUBJECT> <P>(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 203.47 if you have a lease issued with royalty relief provisions for deep-well drilling. Such leases:</P> <P>(1) Must be issued as part of an OCS lease sale held after January 1, 2001, and before April 1, 2004; and</P> <P>(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.</P> <P>(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.</P> <P>(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 203.47.</P> <P>(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.</P> </SECTION> </SUBJGRP> <SUBJGRP> <HD SOURCE="HED">Royalty Relief for End-of-life Leases</HD> <SECTION> <SECTNO>§ 203.50</SECTNO> <SUBJECT>Who may apply for end-of-life royalty relief?</SUBJECT> <P>You may apply for royalty relief in two situations.</P> <P>(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.</P> <P>(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.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.51</SECTNO> <SUBJECT>How do I apply for end-of-life royalty relief?</SUBJECT> <P>You must submit a complete application and the required fee to the appropriate MMS Regional Director. Your MMS regional office will provide specific guidance on the report formats. A complete application for relief includes:</P> <P>(a) An administrative information report (specified in § 203.83) and</P> <P>(b) A net revenue and relief justification report (specified in § 203.84).</P> </SECTION> <SECTION> <SECTNO>§ 203.52</SECTNO> <SUBJECT>What criteria must I meet to get relief?</SUBJECT> <P>(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).</P> <P>(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:</P> <P>(1) You have met the criterion listed in paragraph (a) of this section, and</P> <P>(2) The 12 required qualifying months of operation have occurred under the current royalty arrangement.</P> </SECTION> <SECTION> <SECTNO>§ 203.53</SECTNO> <SUBJECT>What relief will MMS grant?</SUBJECT> <P>(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 <PRTPAGE P="29"/>amount. If you produce more than the relief volume amount:</P> <P>(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</P> <P>(2) We will impose a royalty rate equal to the effective rate on all production greater than twice the relief volume amount.</P> <P>(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.</P> <P>(1) The effective royalty rate is the average lease rate paid on production during the 12 qualifying months.</P> <P>(2) The relief volume amount is the average monthly BOE production for the 12 qualifying months.</P> </SECTION> <SECTION> <SECTNO>§ 203.54</SECTNO> <SUBJECT>How does my relief arrangement for an oil and gas lease operate if prices rise sharply?</SUBJECT> <P>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.</P> <P>(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;</P> <P>(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</P> <P>(c) Your weighting factors are the proportions of your total production volume (in BOE) provided by oil and gas during the qualifying months.</P> </SECTION> <SECTION> <SECTNO>§ 203.55</SECTNO> <SUBJECT>Under what conditions can my end-of-life royalty relief arrangement for an oil and gas lease be ended?</SUBJECT> <P>(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.</P> <P>(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.</P> <P>(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.</P> </SECTION> <SECTION> <SECTNO>§ 203.56</SECTNO> <SUBJECT>Does relief transfer when a lease is assigned?</SUBJECT> <P>Yes. Royalty relief is based on the lease circumstances, not ownership. It transfers upon lease assignment.</P> </SECTION> </SUBJGRP> <SUBJGRP> <HD SOURCE="HED">Royalty Relief For Deep Water Expansion Projects And Pre-Act Deep Water Leases</HD> <SECTION> <SECTNO>§ 203.60</SECTNO> <SUBJECT>Who may apply for deep water royalty relief?</SUBJECT> <P>You may apply for royalty relief under §§ 203.61(b) and 203.62 if:</P> <P>(a) You are a lessee of a lease in water at least 200 meters deep in the GOM and lying wholly west of 87 degrees, 30 minutes West longitude;</P> <P>(b) We have assigned your pre-Act lease to a field (as defined in § 203.0); and</P> <P>(c) You either:</P> <P>(1) Hold a pre-Act lease on an authorized field (as defined in § 203.0) or</P> <P>(2) Propose an expansion project (as defined in § 203.0) or</P> <P>(3) Propose a development project (as defined in § 203.0).</P> <CITA>[67 FR 1875, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.61</SECTNO> <SUBJECT>How do I assess my chances for getting relief?</SUBJECT> <P>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.</P> <P>(a) To request a nonbinding assessment, you must:</P> <P>(1) Submit a draft application in the format and detail specified in guidance from the MMS regional office for the GOM;</P> <P>(2) Propose to drill at least one more appraisal well if you get a favorable assessment; and<PRTPAGE P="30"/> </P> <P>(3) Pay a fee under § 203.3.</P> <P>(b) You must wait at least 90 days after receiving our assessment to apply for relief under § 203.62.</P> <P>(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.</P> <EFFDNOT> <HD SOURCE="HED">Effective Date Note:</HD> <P>At 63 FR 2619, Jan. 16, 1998, § 203.61 was revised. This section contains information collection and recordkeeping requirements and will not become effective until approval has been given by the Office of Management and Budget.</P> </EFFDNOT> </SECTION> <SECTION> <SECTNO>§ 203.62</SECTNO> <SUBJECT>How do I apply for relief?</SUBJECT> <P>You must send a complete application and the required fee to the MMS Regional Director for the GOM.</P> <P>(a) Your application for deep water royalty relief must include an original and two copies (one set of digital information) of:</P> <P>(1) Administrative information report;</P> <P>(2) Deep water economic viability and relief justification report;</P> <P>(3) G&G report;</P> <P>(4) Engineering report;</P> <P>(5) Production report; and</P> <P>(6) Deep water cost report.</P> <P>(b) Section 203.82 explains why we are authorized to require these reports.</P> <P>(c) Sections 203.81, 203.83, and 203.85 through 203.89 describe what these reports must include. The MMS regional office for the GOM will guide you on the format for the required reports, and we encourage you to contact this office prior to preparing your application for this guidance.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.63</SECTNO> <SUBJECT>Does my application have to include all leases in the field?</SUBJECT> <P>(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.</P> <P>(1) The Regional Director maintains a Field Names Master List with updates of all leases in each designated field.</P> <P>(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.</P> <P>(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 ineligible for the royalty relief for the designated field.</P> <P>(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.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.64</SECTNO> <SUBJECT>How many applications may I file on a field or a development project?</SUBJECT> <P>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:</P> <P>(a) You are eligible to apply for a redetermination under § 203.74;</P> <P>(b) You apply for royalty relief for an expansion project;</P> <P>(c) You withdraw the application before we make a determination; or</P> <P>(d) You apply for end-of-life royalty relief.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <PRTPAGE P="31"/> <SECTNO>§ 203.65</SECTNO> <SUBJECT>How long will MMS take to evaluate my application?</SUBJECT> <P>(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.</P> <P>(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.</P> <P>(c) We may ask to extend the review period for your application under the conditions in the following table.</P> <GPOTABLE CDEF="s150,r150" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">If—</CHED> <CHED H="1">Then we may—</CHED> </BOXHD> <ROW> <ENT I="01">We need more records to audit sunk costs</ENT> <ENT>Ask to extend the 120-day or 180-day evaluation period. The extension we request will equal the number of days between when you receive our request for records and the day we receive the records.</ENT> </ROW> <ROW> <ENT I="01">We cannot evaluate your application for a valid reason, such as missing vital information or inconsistent or inconclusive supporting data</ENT> <ENT>Add another 30 days. We may add more than 30 days, but only if you agree.</ENT> </ROW> <ROW> <ENT I="01">We need more data, explanations, or revision</ENT> <ENT>Ask to extend the 120-day or 180-day evaluation period. The extension we request will equal the number of days between when you receive our request and the day we receive the information.</ENT> </ROW> </GPOTABLE> <P>(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.</P> <P>(e) We will notify all designated lease operators within a field when royalty relief is granted.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1875, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.66</SECTNO> <SUBJECT>What happens if MMS does not act in the time allowed?</SUBJECT> <P>If we do not act within the timeframes established under § 203.65, you get royalty relief according to the following table.</P> <GPOTABLE CDEF="s75,r75,r75" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1">If you apply for royalty relief for</CHED> <CHED H="1">And we do not decide within the time specified</CHED> <CHED H="1">As long as you</CHED> </BOXHD> <ROW> <ENT I="01">(a) An authorized field</ENT> <ENT>You get the minimum suspension volumes specified in § 203.69</ENT> <ENT>Abide by §§ 203.70 and 203.76.</ENT> </ROW> <ROW> <ENT I="01">(b) An expansion project</ENT> <ENT>You get a royalty suspension for the first year of production</ENT> <ENT>Abide by §§ 203.70 and 203.76.</ENT> </ROW> <ROW> <ENT I="01">(c) A development project</ENT> <ENT>You get a royalty suspension for initial production for the number of months that a decision is delayed beyond the stipulated timeframes set by § 203.65, plus all the royalty suspension volume for which you qualify</ENT> <ENT>Abide by §§ 203.70 and 203.76.</ENT> </ROW> </GPOTABLE> <CITA>[67 FR 1875, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.67</SECTNO> <SUBJECT>What economic criteria must I meet to get royalty relief on an authorized field or project?</SUBJECT> <P>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.</P> <CITA>[67 FR 1876, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <PRTPAGE P="32"/> <SECTNO>§ 203.68</SECTNO> <SUBJECT>What pre-application costs will MMS consider in determining economic viability?</SUBJECT> <P>(a) We will not consider ineligible costs as set forth in § 203.89(h) in determining economic viability for purposes of royalty relief.</P> <P>(b) We will consider sunk costs according to the following table.</P> <GPOTABLE CDEF="s75,r100" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">We will</CHED> <CHED H="1">When determining</CHED> </BOXHD> <ROW> <ENT I="01">(1) Include sunk costs</ENT> <ENT>Whether a field that includes a pre-Act lease which has not produced, other than test production, before the application or redetermination submission date needs relief to become economic.</ENT> </ROW> <ROW> <ENT I="01">(2) Not include sunk costs</ENT> <ENT>Whether an authorized field, a development project, or an expansion project can become economic with full relief (see § 203.67).</ENT> </ROW> <ROW> <ENT I="01">(3) Not include sunk costs</ENT> <ENT>How much suspension volume is necessary to make the field, a development project, or an expansion project economic (see § 203.69(c)).</ENT> </ROW> <ROW> <ENT I="01">(4) Include sunk costs for the project discovery well on each lease</ENT> <ENT>Whether a development project or an expansion project needs relief to become economic.</ENT> </ROW> </GPOTABLE> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.69</SECTNO> <SUBJECT>If my application is approved, what royalty relief will I receive?</SUBJECT> <P>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).</P> <P>(a) For authorized fields, the minimum royalty-suspension volumes are:</P> <P>(1) 17.5 million barrels of oil equivalent (MMBOE) for fields in 200 to 400 meters of water;</P> <P>(2) 52.5 MMBOE for fields in 400 to 800 meters of water; and</P> <P>(3) 87.5 MMBOE for fields in more than 800 meters of water.</P> <P>(b) For development projects, any relief we grant applies only to project wells and replaces the royalty suspension volume with which we issued your lease. If your project is economic given the royalty suspension volume with which we issued your lease, we will reject the application. Otherwise, the <E T="03">minimum</E> royalty suspension volumes are as shown in the following table:</P> <GPOTABLE CDEF="s75,r100,r75" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1">For</CHED> <CHED H="1">The minimum royalty suspension volume is</CHED> <CHED H="1">Plus</CHED> </BOXHD> <ROW> <ENT I="01">(1) RS leases</ENT> <ENT>A volume equal to the combined royalty suspension volumes (or the volume equivalent based on the data in your approved application for other forms of royalty suspension) with which we issued the leases participating in the application that have or plan a well into a reservoir identified in the application</ENT> <ENT O="xl">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 the project.</ENT> </ROW> <ROW> <ENT I="01">(2) Other deep water leases issued in sales after November 28, 2000</ENT> <ENT O="xl">A volume equal to 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 the project.</ENT> <ENT O="xl"/> </ROW> </GPOTABLE> <P>(c) If your application includes pre-Act or eligible 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 “Field Names Master List” documents and updates in effect at the time your application is deemed complete. These publications are available from the MMS Regional Office for the GOM.</P> <P>(d) You will get a royalty suspension volume above the minimum if we determine that you need more to make <PRTPAGE P="33"/>the field or development project economic.</P> <P>(e) 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.</P> <P>(f) 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.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1876, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.70</SECTNO> <SUBJECT>What information must I provide after MMS approves relief?</SUBJECT> <P>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 the GOM will prescribe the formats.</P> <GPOTABLE CDEF="s75,r75,r75" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1">Required report</CHED> <CHED H="1">When due to MMS</CHED> <CHED H="1">Due date extensions</CHED> </BOXHD> <ROW> <ENT I="01">(a) Fabricator's confirmation report</ENT> <ENT>Within 18 months after approval of relief</ENT> <ENT>MMS Director may grant you an extension under § 203.79(c) for up to 6 months.</ENT> </ROW> <ROW> <ENT I="01">(b) Post-production report</ENT> <ENT>Within 120 days after the start of production that is subject to the approved royalty suspension volume</ENT> <ENT>With acceptable justification from you, MMS Regional Director for the GOM may extend due date up to 30 days.</ENT> </ROW> </GPOTABLE> <CITA>[67 FR 1876, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.71</SECTNO> <SUBJECT>How does MMS allocate a field's suspension volume between my lease and other leases on my field?</SUBJECT> <P>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.</P> <P>(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:</P> <GPOTABLE CDEF="s75,r75,r75" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1">If . . .</CHED> <CHED H="1">Then . . .</CHED> <CHED H="1">And . . .</CHED> </BOXHD> <ROW> <ENT I="01">(1) We assign an eligible lease to your field after we approve relief</ENT> <ENT>We will not change your field's royalty suspension volume</ENT> <ENT>The assigned lease(s) may share in any remaining royalty relief.</ENT> </ROW> <ROW> <ENT I="01">(2) We assign a pre-Act or post-November 2000 deep water lease to your field after we approve your application</ENT> <ENT>We will not change your field's royalty suspension volume</ENT> <ENT>The assigned lease(s) may share in any remaining royalty relief by filing the short-form application specified in § 203.83 and authorized in § 203.82. An assigned RS lease also gets any portion of its royalty suspension volume remaining even after the field has produced the approved relief volume.</ENT> </ROW> <ROW> <PRTPAGE P="34"/> <ENT I="01">(3) We assign another lease(s) that you operate to your field while we are evaluating your application</ENT> <ENT>We will change your field's minimum suspension volume if the assigned lease is a pre-Act or eligible lease entitled to a larger minimum or automatic suspension volume</ENT> <ENT>(i) You toll the time period for evaluation until you modify your application to be consistent with the new field;<LI>(ii) We have an additional 60 days to review the new information; and</LI> <LI>(iii) The assigned lease(s) shares the royalty suspension we grant to the new field. If you do not agree to toll, we will have to reject your application due to incomplete information. But, an eligible lease we assigned to the field kept its automatic suspension volume.</LI> </ENT> </ROW> <ROW> <ENT I="01">(4) We assign another operator's lease to your field while we are evaluating your application</ENT> <ENT>We will change your field's minimum suspension volume provided the assigned lease joins the application and is entitled to a larger minimum suspension volume</ENT> <ENT>(i) You both toll the time period for evaluation until both of you modify your application to be consistent with the new field;<LI>(ii) We have an additional 60 days to review the new information; and</LI> <LI>(iii) The assigned lease(s) shares the royalty suspension we grant to the new field. If you (the original applicant) do not agree to toll, the other operator's lease retains any suspension volume it has or may share in any relief that we grant by filing the short form application specified in § 203.83 and authorized in § 203.82.</LI> </ENT> </ROW> <ROW> <ENT I="01">(5) We reassign a well on a pre-Act, eligible, or post-November 2000 deep water lease to another field</ENT> <ENT>The past production from the well counts toward the royalty suspension volume of the field to which we assigned the well</ENT> <ENT>The past production from that well will not count toward any royalty suspension volume granted to the field from which we reassigned it.</ENT> </ROW> </GPOTABLE> <P>(b) If your authorized field has a royalty suspension volume established under § 260.111 of this title (<E T="03">i.e.</E>, a field with a pre-Act lease where an eligible lease starts production first), we will suspend payment of royalties on production from all eligible leases in the field until their cumulative production equals the established volume. The following conditions also apply:</P> <GPOTABLE CDEF="s75,r75,r75" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1">If . . .</CHED> <CHED H="1">Then . . .</CHED> <CHED H="1">And . . .</CHED> </BOXHD> <ROW> <ENT I="01">(1) We assign another eligible lease to your field</ENT> <ENT>Your field's royalty suspension volume does not change</ENT> <ENT>The assigned lease may share in any remaining royalty relief.</ENT> </ROW> <ROW> <ENT I="01">(2) We assign an RS lease to your field</ENT> <ENT>Your field's royalty suspension volume does not change</ENT> <ENT>The assigned lease gets only the volume suspension with which we issued it, and its production volume counts against the field's royalty suspension volume.</ENT> </ROW> <ROW> <ENT I="01">(3) We assign a pre-Act lease or a lease issued after November 2000 without royalty suspension to your field</ENT> <ENT>Your field's royalty suspension volume does not change</ENT> <ENT>We assign lease shares none of the volume suspension, and its production does not count as part of the suspension volume.</ENT> </ROW> <ROW> <ENT I="01">(4) A pre-Act or post-November 2000 deep water lease applies (along with the other leases in the field) and qualifies (subject to any pre-existing suspension volumes) for royalty relief under §§ 203.67 and 203.69</ENT> <ENT>Your field's royalty suspension volume may increase or stay the same, but will not diminish</ENT> <ENT>(i) All leases in the field share the royalty suspension volume if we approve the application; or<LI>(ii) The eligible or RS leases in the field keep their respective volumes if we reject the application.</LI> </ENT> </ROW> </GPOTABLE> <P>(c) 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.</P> <P>(d) You may receive a royalty-suspension volume only if your entire lease is west of 87 degrees, 30 minutes West longitude. If the field lies on both <PRTPAGE P="35"/>sides of this meridian, only leases located entirely west of the meridian will receive a royalty-suspension volume.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1877, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.72</SECTNO> <SUBJECT>Can my lease receive more than one suspension volume?</SUBJECT> <P>Yes. You may apply for royalty relief that involves more than one suspension volume under § 203.62 in two circumstances.</P> <P>(a) Each field that includes your lease may receive a separate royalty-suspension volume, if it meets the evaluation criteria of § 203.67.</P> <P>(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.</P> </SECTION> <SECTION> <SECTNO>§ 203.73</SECTNO> <SUBJECT>How do suspension volumes apply to natural gas?</SUBJECT> <P>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.</P> </SECTION> <SECTION> <SECTNO>§ 203.74</SECTNO> <SUBJECT>When will MMS reconsider its determination?</SUBJECT> <P>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.</P> <P>(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:</P> <P>(1) Results from drilling new wells or getting new three-dimensional seismic data and information (but not reinterpreting old data);</P> <P>(2) Did not exist at the time of the earlier application; and</P> <P>(3) Changes your estimates of gross resource size, quality, or projected flow rates enough to materially affect the results of our earlier determination.</P> <P>(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.</P> <P>(c) Your current reference price decreases by more than 25 percent from your base reference price as calculated under this paragraph.</P> <P>(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;</P> <P>(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</P> <P>(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.</P> <P>(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.</P> <CITA>[63 FR 2618, Jan. 16, 1998; 63 FR 24747, May 5, 1998, as amended at 67 FR 1878, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.75</SECTNO> <SUBJECT>What risk do I run if I request a redetermination?</SUBJECT> <P>If you request a redetermination after we have granted you a suspension <PRTPAGE P="36"/>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.</P> </SECTION> <SECTION> <SECTNO>§ 203.76</SECTNO> <SUBJECT>When might MMS withdraw or reduce the approved size of my relief?</SUBJECT> <P>We will withdraw approval of relief for any of the following reasons.</P> <P>(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.).</P> <P>(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.</P> <P>(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.</P> <P>(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.</P> <P>(e) You do not send us the fabrication confirmation report or the post-production development report, or you provide false or intentionally inaccurate information that was material to our granting royalty relief under this section. You must pay royalties and late-payment interest determined under 30 U.S.C. 1721 and § 218.54 of this chapter on all volumes for which you used the royalty suspension. You also may be subject to penalties under other provisions of law.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.77</SECTNO> <SUBJECT>May I voluntarily give up relief if conditions change?</SUBJECT> <P>Yes, by sending a letter to that effect to the MMS Regional Director for the GOM.</P> <CITA>[67 FR 1878, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.78</SECTNO> <SUBJECT>Do I keep relief if prices rise significantly?</SUBJECT> <P>If prices rise above a base price for light sweet crude oil or natural gas, set by statute for pre-Act leases, indicated in your original lease agreement or Notice of Sale for post-November 2000 deep water leases, you must pay full royalties as prescribed in this section. For post-November 2000 deepwater leases, price thresholds apply on a lease basis, so different leases on the same field, development project, or expansion project may have different price thresholds.</P> <P>(a) Suppose the arithmetic average of the daily closing NYMEX light sweet crude oil prices for the previous calendar year exceeds $28.00 per barrel, as adjusted in paragraph (f) of this section. In this case, we retract the royalty relief authorized in this section and you must:<PRTPAGE P="37"/> </P> <P>(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</P> <P>(2) Pay royalties on all your oil production in the current year.</P> <P>(b) Suppose the arithmetic average of the daily closing NYMEX natural gas prices for the previous calendar year exceeds $3.50 per million British thermal units (Btu), as adjusted in paragraph (f) of this section. In this case, we retract the royalty relief authorized in this section and you must:</P> <P>(1) Pay royalties on all natural gas production for the previous year at the lease stipulated royalty rate plus interest (under 30 U.S.C. 1721 and § 218.54 of this chapter) by March 31 of the current calendar year, and</P> <P>(2) Pay royalties on all your natural gas production in the current year.</P> <P>(c) Production under both paragraphs (a) and (b) of this section counts as part of the royalty-suspension volume.</P> <P>(d) You are entitled to a refund or credit, with interest, of royalties paid on any production (that counts as part of the royalty-suspension volume):</P> <P>(1) Of oil if the arithmetic average of the closing oil prices for the current calendar year is $28.00 per barrel or less, as adjusted in paragraph (f) of this section, and</P> <P>(2) Of gas if the arithmetic average of the closing natural gas prices for the current calendar year is $3.50 per million Btu or less, as adjusted in paragraph (f) of this section.</P> <P>(e) You must follow our regulations in part 230 of this chapter for receiving refunds or credits.</P> <P>(f) We change the prices referred to in paragraphs (a), (b), and (d) 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.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1878, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.79</SECTNO> <SUBJECT>How do I appeal MMS's decisions related to Deep Water Royalty Relief?</SUBJECT> <P>(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.</P> <P>(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.</P> <P>(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.</P> <P>(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) <E T="03">only</E> if you file an action within 30 days of the date you receive our decision.</P> </SECTION> <SECTION> <SECTNO>§ 203.80</SECTNO> <SUBJECT>When can I get royalty relief if I am not eligible for end-of-life or deep water royalty relief?</SUBJECT> <P>We may grant royalty relief when it serves the statutory purposes summarized in § 203.1, and our formal relief programs provide inadequate encouragement to increase production or development. Unless your lease lies wholly west of 87 degrees, 30 minutes West longitude in the Gulf of Mexico, your lease must be producing to qualify for relief. Before you may apply for royalty relief apart from our end-of-life or deepwater programs, we must agree that your lease or project has two or more of the following characteristics:</P> <P>(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 <PRTPAGE P="38"/>a year more than would be profitable without royalty relief.</P> <P>(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.</P> <P>(c) A substantial risk exists that no new lessee will recover the resources.</P> <P>(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).</P> <P>(e) Circumstances beyond the lessee's control, other than water depth, preclude reliance on one of the existing royalty relief programs.</P> <CITA>[67 FR 1879, Jan. 15, 2002]</CITA> </SECTION> </SUBJGRP> <SUBJGRP> <HD SOURCE="HED">Required Reports</HD> <SECTION> <SECTNO>§ 203.81</SECTNO> <SUBJECT>What supplemental reports do royalty-relief applications require?</SUBJECT> <P>(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.</P> <GPOTABLE CDEF="s75,7C,11C,7C,11C" COLS="5" OPTS="L2"> <BOXHD> <CHED H="1">Required reports</CHED> <CHED H="1">End-of-life lease</CHED> <CHED H="1">Deep water</CHED> <CHED H="2">Expansion project</CHED> <CHED H="2">Pre-act lease</CHED> <CHED H="2">Development project</CHED> </BOXHD> <ROW> <ENT I="01">(1) Administrative information Report</ENT> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(2) Net revenue & relief justification report</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(3) Economic viability & relief justification report (RSVP model imputs justified by other required reports).</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(4) G&G report.</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(5) Engineering report.</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(6) Production report.</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(7) Deep water cost report</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(8) Fabricator's confirmation report.</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> <ROW> <ENT I="01">(9) Post-production development report.</ENT> <ENT/> <ENT>X</ENT> <ENT>X</ENT> <ENT>X</ENT> </ROW> </GPOTABLE> <P>(b) You must certify that all information in your application, fabricator's confirmation and post-production development reports is accurate, complete, and conforms to the most recent content and presentation guidelines available from the MMS GOM Regional Office.</P> <P>(c) With your application and post-production development report, you must submit an additional report prepared by an independent CPA that:</P> <P>(1) Assesses the accuracy of the historical financial information in your report; and</P> <P>(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—</P> <P>(i) Include only eligible costs that are incurred during the qualification months; and</P> <P>(ii) Be shown in the proper format.</P> <P>(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.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.82</SECTNO> <SUBJECT>What is MMS's authority to collect this information?</SUBJECT> <P>The Office of Management and Budget (OMB) approved the information collection requirements in part 203 under 44 U.S.C. 3501 <E T="03">et seq.</E> and assigned OMB control number 1010-0071.</P> <P>(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.</P> <P>(1) Your application for royalty relief must contain enough information on finances, economics, reservoirs, G&G <PRTPAGE P="39"/>characteristics, production, and engineering estimates for us to determine whether:</P> <P>(i) We should grant relief under the law, and</P> <P>(ii) The requested relief will ultimately recover more resources and return a reasonable profit on project investments.</P> <P>(2) Your fabricator confirmation and post-production development reports must contain enough information for us to verify that your application reasonably represented your plans.</P> <P>(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.</P> <P>(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.</P> <P>(d) Send comments regarding any aspect of the collection of information under this part, including suggestions for reducing the burden, to the Information Collection Clearance Officer, Minerals Management Service, Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 65 FR 2875, Jan. 19, 2000]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.83</SECTNO> <SUBJECT>What is in an administrative information report?</SUBJECT> <P>This report identifies the field or lease for which royalty relief is requested and must contain the following items:</P> <P>(a) The field or lease name;</P> <P>(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;</P> <P>(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);</P> <P>(d) The location of any new wells proposed under the terms of the application (not required for non-oil and gas leases);</P> <P>(e) A description of field or lease history;</P> <P>(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;</P> <P>(g) The type of royalty relief you are requesting;</P> <P>(h) Confirmation that we approved a DOCD or supplemental DOCD (Deep Water expansion project applications only); and</P> <P>(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).</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.84</SECTNO> <SUBJECT>What is in a net revenue and relief justification report?</SUBJECT> <P>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.</P> <P>(a) The cash flow table you submit must include historical data for:</P> <P>(1) Lease production subject to royalty;</P> <P>(2) Total revenues;</P> <P>(3) Royalty payments out of production;</P> <P>(4) Total allowable costs; and</P> <P>(5) Transportation and processing costs.</P> <P>(b) Do not include in your cash flow table the non-allowable costs listed at 30 CFR 220.013 or:</P> <P>(1) OCS rental payments on the lease(s) in the application;</P> <P>(2) Damages and losses;</P> <P>(3) Taxes;<PRTPAGE P="40"/> </P> <P>(4) Any costs associated with exploratory activities;</P> <P>(5) Civil or criminal fines or penalties;</P> <P>(6) Fees for your royalty relief application; and</P> <P>(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).</P> <P>(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.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 63 FR 57249, Oct. 27, 1998]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.85</SECTNO> <SUBJECT>What is in an economic viability and relief justification report?</SUBJECT> <P>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.</P> <P>(a) Economic assumptions we provide which include:</P> <P>(1) Starting oil and gas prices;</P> <P>(2) Real price growth;</P> <P>(3) Real cost growth or decline rate, if any;</P> <P>(4) Base year;</P> <P>(5) Range of discount rates; and</P> <P>(6) Tax rate (for use in determining after-tax sunk costs).</P> <P>(b) Analysis of projected cash flow (from the date of the application using annual totals and constant dollar values) which shows:</P> <P>(1) Oil and gas production;</P> <P>(2) Total revenues;</P> <P>(3) Capital expenditures;</P> <P>(4) Operating costs;</P> <P>(5) Transportation costs; and</P> <P>(6) Before-tax net cash flow without royalties, overrides, sunk costs, and ineligible costs.</P> <P>(c) Discounted values which include:</P> <P>(1) Discount rate used (selected from within the range we specify).</P> <P>(2) Before-tax net present value without royalties, overrides, sunk costs, and ineligible costs.</P> <P>(d) Demonstrations that:</P> <P>(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</P> <P>(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.</P> </SECTION> <SECTION> <SECTNO>§ 203.86</SECTNO> <SUBJECT>What is in a G&G report?</SUBJECT> <P>This report supports the reserve and resource estimates used in the economic evaluation and must contain each of the following elements.</P> <P>(a) Seismic data which includes:</P> <P>(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;</P> <P>(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;</P> <P>(3) Digital velocity surveys in the format of the GOM region's letter to lessees of 10/1/90;</P> <P>(4) Plat map of “shot points;” and</P> <P>(5) “Time slices” of potential horizons.</P> <P>(b) Well data which includes:</P> <P>(1) Hard copies of all well logs in which—</P> <P>(i) The 1-inch electric log shows pay zones and pay counts and lithologic and paleo correlation markers at least every 500-feet,</P> <P>(ii) The 1-inch type log shows missing sections from other logs where faulting occurs,<PRTPAGE P="41"/> </P> <P>(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<E T="52">o</E>) and the resistivity of the undisturbed formation (R<E T="52">t</E>), and</P> <P>(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;</P> <P>(2) Digital copies of all well logs spudded before December 1, 1995;</P> <P>(3) Core data, if available;</P> <P>(4) Well correlation sections;</P> <P>(5) Pressure data;</P> <P>(6) Production test results;</P> <P>(7) Pressure-volume-temperature analysis, if available; and</P> <P>(8) A table listing the wells and completions, and indicating which sands and fault blocks will be targeted for completion or recompletion.</P> <P>(c) Map interpretations which includes for each reservoir in the field:</P> <P>(1) Structure maps consisting of top and base of sand maps showing well and seismic shot point locations;</P> <P>(2) Isopach maps for net sand, net oil, net gas, all with well locations;</P> <P>(3) Maps indicating well surface and bottom hole locations, location of development facilities, and shot points; and</P> <P>(4) An explanation for excluding the reservoirs you are not planning to develop.</P> <P>(d) Reservoir-specific data which includes:</P> <P>(1) Probability of reservoir occurrence with hydrocarbons;</P> <P>(2) Probability the hydrocarbon in the reservoir is all oil and the probability it is all gas;</P> <P>(3) Distributions or point estimates (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for the parameters used to estimate reservoir size, <E T="03">i.e.</E>, acres and net thickness;</P> <P>(4) Most likely values for porosity, salt water saturation, volume factor for oil formation, and volume factor for gas formation;</P> <P>(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);</P> <P>(6) A gas/oil ratio distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each reservoir;</P> <P>(7) A yield distribution or point estimate (accompanied by explanations of why distributions less appropriately reflect the uncertainty) for each gas reservoir; and</P> <P>(8) Reserve or resource distribution by reservoir.</P> <P>(e) Aggregated reserve and resource data which includes:</P> <P>(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;</P> <P>(2) A description of anticipated hydrocarbon quality (<E T="03">i.e.</E>, specific gravity); and</P> <P>(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.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1879, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.87</SECTNO> <SUBJECT>What is in an engineering report?</SUBJECT> <P>This report defines the development plan and capital requirements for the economic evaluation and must contain the following elements.</P> <P>(a) A description of the development concept (e.g., tension leg platform, fixed platform, floater type, subsea tieback, etc.) which includes:</P> <P>(1) Its size along with basic design specifications and drawings; and</P> <P>(2) The construction schedule.<PRTPAGE P="42"/> </P> <P>(b) An identification of planned wells which includes:</P> <P>(1) The number;</P> <P>(2) The type (platform, subsea, vertical, deviated, horizontal);</P> <P>(3) The well depth;</P> <P>(4) The drilling schedule;</P> <P>(5) The kind of completion (single, dual, horizontal, etc.); and</P> <P>(6) The completion schedule.</P> <P>(c) A description of the production system equipment which includes:</P> <P>(1) The production capacity for oil and gas and a description of limiting component(s);</P> <P>(2) Any unusual problems (low gravity, paraffin, etc.);</P> <P>(3) All subsea structures;</P> <P>(4) All flowlines; and</P> <P>(5) Schedule for installing the production system.</P> <P>(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.</P> <P>(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.</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.88</SECTNO> <SUBJECT>What is in a production report?</SUBJECT> <P>This report supports your development and production timing and product quality expectations and must contain the following elements.</P> <P>(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.</P> <P>(b) Production drive mechanisms for each reservoir.</P> </SECTION> <SECTION> <SECTNO>§ 203.89</SECTNO> <SUBJECT>What is in a deep water cost report?</SUBJECT> <P>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.</P> <P>(a) Sunk costs. Report sunk costs in dollars not adjusted for inflation and only if you have documentation.</P> <P>(b) Appraisal, delineation and development costs. Base them on actual spending, current authorization for expenditure, engineering estimates, or analogous projects. These costs cover:</P> <P>(1) Platform well drilling and average depth;</P> <P>(2) Platform well completion;</P> <P>(3) Subsea well drilling and average depth;</P> <P>(4) Subsea well completion;</P> <P>(5) Production system (platform); and</P> <P>(6) Flowline fabrication and installation.</P> <P>(c) Production costs based on historical costs, engineering estimates, or analogous projects. These costs cover:</P> <P>(1) Operation;</P> <P>(2) Equipment; and</P> <P>(3) Existing royalty overrides (we will not use the royalty overrides in evaluations).</P> <P>(d) Transportation costs, based on historical costs, engineering estimates, or analogous projects. These costs cover:</P> <P>(1) Oil or gas tariffs from pipeline or tankerage;</P> <P>(2) Trunkline and tieback lines; and</P> <P>(3) Gas plant processing for natural gas liquids.</P> <P>(e) Abandonment costs, based on historical costs, engineering estimates, or analogous projects. You should provide the costs to plug and abandon only wells and to remove only production systems for which you have not incurred costs as of the time of application submission. You should also include a point estimate or distribution of prospective salvage value for all potentially reusable facilities and materials, along with the source and an explanation of the figures provided.<PRTPAGE P="43"/> </P> <P>(f) A set of cost estimates consistent with each one of up to three field-development scenarios and production profiles (conservative, most likely, optimistic). You should express costs in constant real dollar terms for the base year. You may also express the uncertainty of each cost estimate with a minimum and maximum percentage of the base value.</P> <P>(g) A spending schedule. You should provide costs for each year (in real dollars) for each category in paragraphs (a) through (f) of this section.</P> <P>(h) A summary of other costs which are ineligible for evaluating your need for relief. These costs cover:</P> <P>(1) Expenses before first discovery on the field;</P> <P>(2) Cash bonuses;</P> <P>(3) Fees for royalty relief applications;</P> <P>(4) Lease rentals, royalties, and payments of net profit share and net revenue share;</P> <P>(5) Legal expenses;</P> <P>(6) Damages and losses;</P> <P>(7) Taxes;</P> <P>(8) Interest or finance charges, including those embedded in equipment leases;</P> <P>(9) Fines or penalties; and</P> <P>(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).</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.90</SECTNO> <SUBJECT>What is in a fabricator's confirmation report?</SUBJECT> <P>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):</P> <P>(a) A copy of the contract(s) under which the fabrication yard is building the approved system for you;</P> <P>(b) A letter from the contractor building the system to the MMS's GOM Regional Supervisor—Production and Development, certifying when construction started on your system; and</P> <P>(c) Evidence of an appropriate down payment or equal action that you've started acquiring the approved system.</P> </SECTION> <SECTION> <SECTNO>§ 203.91</SECTNO> <SUBJECT>What is in a post-production development report?</SUBJECT> <P>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).</P> <CITA>[63 FR 2618, Jan. 16, 1998, as amended at 67 FR 1880, Jan. 15, 2002]</CITA> </SECTION> </SUBJGRP> </SUBPART> <SUBPART> <RESERVED>Subpart C—Federal and Indian Oil [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Federal and Indian Gas [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Coal</HD> <SECTION> <SECTNO>§ 203.250</SECTNO> <SUBJECT>Advance royalty.</SUBJECT> <P>Provisions for the payment of advance royalty in lieu of continued operation are contained at 43 CFR 3483.4.</P> <CITA>[54 FR 1522, Jan. 13, 1989]</CITA> </SECTION> <SECTION> <SECTNO>§ 203.251</SECTNO> <SUBJECT>Reduction in royalty rate or rental.</SUBJECT> <P>An application for reduction in coal royalty rate or rental shall be filed and processed in accordance with 43 CFR group 3400.</P> <CITA>[54 FR 1522, Jan. 13, 1989]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart H—Geothermal Resources [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> </PART> <PART> <PRTPAGE P="44"/> <EAR>Pt. 204</EAR> <HD SOURCE="HED">PART 204—ALTERNATIVES FOR MARGINAL PROPERTIES</HD> <CONTENTS> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECHD>Sec.</SECHD> <SECTNO>204.1</SECTNO> <SUBJECT>What is the purpose of this part?</SUBJECT> <SECTNO>204.2</SECTNO> <SUBJECT>What definitions apply to this part?</SUBJECT> <SECTNO>204.3</SECTNO> <SUBJECT>What alternatives are available for marginal properties?</SUBJECT> <SECTNO>204.4</SECTNO> <SUBJECT>What is a marginal property under this part?</SUBJECT> <SECTNO>204.5</SECTNO> <SUBJECT>What statutory requirements must I meet to obtain royalty prepayment or accounting and auditing relief?</SUBJECT> <SECTNO>204.6</SECTNO> <SUBJECT>May I appeal if MMS denies my request for prepayment or other relief?</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart B—Prepayment of Royalty [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Accounting and Auditing Relief</HD> <SECTNO>204.200</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <SECTNO>204.201</SECTNO> <SUBJECT>Who may obtain accounting and auditing relief?</SUBJECT> <SECTNO>204.202</SECTNO> <SUBJECT>What is the cumulative royalty reports and payments relief option?</SUBJECT> <SECTNO>204.203</SECTNO> <SUBJECT>What is the other relief option?</SUBJECT> <SECTNO>204.204</SECTNO> <SUBJECT>What accounting and auditing relief will MMS not allow?</SUBJECT> <SECTNO>204.205</SECTNO> <SUBJECT>How do I obtain accounting and auditing relief?</SUBJECT> <SECTNO>204.206</SECTNO> <SUBJECT>What will MMS do when it receives my request for other relief?</SUBJECT> <SECTNO>204.207</SECTNO> <SUBJECT>Who will approve, deny, or modify my request for accounting and auditing relief?</SUBJECT> <SECTNO>204.208</SECTNO> <SUBJECT>May a State decide that it will or will not allow one or both of the relief options under this subpart?</SUBJECT> <SECTNO>204.209</SECTNO> <SUBJECT>What if a property ceases to qualify for relief obtained under this subpart?</SUBJECT> <SECTNO>204.210</SECTNO> <SUBJECT>What if a property is approved as part of a nonqualifying agreement?</SUBJECT> <SECTNO>204.211</SECTNO> <SUBJECT>When may MMS rescind relief for a property?</SUBJECT> <SECTNO>204.212</SECTNO> <SUBJECT>What if I took relief for which I was ineligible?</SUBJECT> <SECTNO>204.213</SECTNO> <SUBJECT>May I obtain relief for a property that benefits from other Federal or State incentive programs?</SUBJECT> <SECTNO>204.214</SECTNO> <SUBJECT>Is minimum royalty due on a property for which I took relief?</SUBJECT> <SECTNO>204.215</SECTNO> <SUBJECT>Are the information collection requirements in this subpart approved by the Office of Management and Budget (OMB)?</SUBJECT> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>30 U.S.C. 1701 <E T="03">et seq.</E> </P> </AUTH> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>69 FR 55088, Sept. 13, 2004, unless otherwise noted.</P> </SOURCE> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECTION> <SECTNO>§ 204.1</SECTNO> <SUBJECT>What is the purpose of this part?</SUBJECT> <P>This part explains how you as a lessee or designee of a Federal onshore or Outer Continental Shelf (OCS) oil and gas lease may obtain prepayment or accounting and auditing relief for production from certain marginal properties. This part does not apply to production from Indian leases, even if the Indian lease is within an agreement that qualifies as a marginal property.</P> </SECTION> <SECTION> <SECTNO>§ 204.2</SECTNO> <SUBJECT>What definitions apply to this part?</SUBJECT> <P> <E T="03">Agreement</E> means a federally approved communitization agreement or unit participating area.</P> <P> <E T="03">Barrels of oil equivalent (BOE)</E> means the combined equivalent production of oil and gas stated in barrels of oil. Each barrel of oil production is equal to one BOE. Also, each 6,000 cubic feet of gas production is equal to one BOE.</P> <P> <E T="03">Base period</E> means the 12-month period from July 1 through June 30 immediately preceding the calendar year for which you take or request marginal property relief. For example, if you request relief for calendar year 2006, your base period is July 1, 2004, through June 30, 2005.</P> <P> <E T="03">Combined equivalent production</E> means the total of all oil and gas production for the marginal property, stated in BOE.</P> <P> <E T="03">Designee</E> means the person designated by a lessee under 30 CFR 218.52 to make all or part of the royalty or other payments due on a lease on the lessee's behalf.</P> <P> <E T="03">Producing wells</E> means only those producing oil or gas wells that contribute to the sum of BOE used in the calculation under § 204.4(c). Producing wells do not include injection or water wells. Wells with multiple zones commingled downhole are considered as a single well.</P> <P> <E T="03">Property</E> means a lease, a portion of a lease, or an agreement that may be a marginal property if it meets the qualification requirements of § 204.4.</P> <P> <E T="03">State concerned (State)</E> means the State that receives a statutorily prescribed portion of the royalties from a Federal onshore or OCS lease.</P> </SECTION> <SECTION> <PRTPAGE P="45"/> <SECTNO>§ 204.3</SECTNO> <SUBJECT>What alternatives are available for marginal properties?</SUBJECT> <P>If you have production from a marginal property, MMS and the State may allow you the following options:</P> <P>(a) <E T="03">Prepay royalty.</E> MMS and the State may allow you to make a lump-sum advance payment of royalties instead of monthly royalty payments for the remainder of the lease term. See Subpart B for prepayment of royalty requirements.</P> <P>(b) <E T="03">Take accounting and auditing relief.</E> MMS and the State may allow various accounting and auditing relief options to encourage you to continue to produce and develop your marginal property. See Subpart C for accounting and auditing relief requirements.</P> </SECTION> <SECTION> <SECTNO>§ 204.4</SECTNO> <SUBJECT>What is a marginal property under this part?</SUBJECT> <P>(a) To qualify as a marginal property eligible for royalty prepayment or accounting and auditing relief under this part, the property must meet the following requirements:</P> <GPOTABLE CDEF="s75,r75,r75" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1" O="L">If your lease is . . .</CHED> <CHED H="1" O="L">Then . . .</CHED> <CHED H="1" O="L">And . . .</CHED> </BOXHD> <ROW> <ENT I="01">(1) Not in an agreement</ENT> <ENT>The lease must qualify as a marginal property under paragraph (b) of this section</ENT> <ENT/> </ROW> <ROW> <ENT I="01">(2) Entirely or partly committed to one agreement</ENT> <ENT>The entire agreement must qualify as a marginal property under paragraph (b) of this section</ENT> <ENT>Agreement production allocable to your lease may be eligible for relief under this part. Any production from your lease that is not committed to the agreement also may be eligible for separate relief under paragraph (a)(4) of this table.</ENT> </ROW> <ROW> <ENT I="01">(3) Entirely or partly committed to more than one agreement</ENT> <ENT>Each agreement must qualify separately as a marginal property under paragraph (b) of this section</ENT> <ENT>For any agreement that does qualify, that agreement's production allocable to your lease may be eligible for relief under this part. Any production from your lease that is not committed to an agreement also may be eligible for separate relief under paragraph (a)(4) of this table.</ENT> </ROW> <ROW> <ENT I="01">(4) Partly committed to an agreement and you have production from the part of the lease that is not committed to the agreement</ENT> <ENT>The part of the lease that is not committed to the agreement must qualify separately as a marginal property under paragraph (b) of this section</ENT> </ROW> </GPOTABLE> <P>(b) To qualify as a marginal property for a calendar year, the combined equivalent production of the property during the base period must equal an average daily well production of less than 15 barrels of oil equivalent (BOE) per well per day calculated under paragraph (c) of this section.</P> <P>(c) To determine the average daily well production for a property, divide the sum of the BOE for all producing wells on the property during the base period by the sum of the number of days that each of those wells actually produced during the base period. If the property is an agreement, your calculation under this paragraph must include all wells included in the agreement, even if they are not on a Federal onshore or OCS lease.</P> </SECTION> <SECTION> <SECTNO>§ 204.5</SECTNO> <SUBJECT>What statutory requirements must I meet to obtain royalty prepayment or accounting and auditing relief?</SUBJECT> <P>(a) MMS and the State may allow royalty prepayment or accounting and auditing relief for your marginal property production if MMS and the State jointly determine that the prepayment or accounting and auditing relief is in the best interests of the Federal Government and the State to:</P> <P>(1) Promote production;</P> <P>(2) Reduce the administrative costs of MMS and the State; and</P> <P>(3) Increase net receipts to the Federal Government and the State.</P> <P>(b) At any time, if MMS and the State determine that either prepayment or accounting and auditing relief no longer meets the criteria in paragraph (a) of this section, MMS, with <PRTPAGE P="46"/>the State's concurrence, may discontinue any prepayment or accounting and auditing relief options granted for production from any marginal property.</P> <P>(1) MMS will provide you written notice of the decision to discontinue relief.</P> <P>(i) If you took the cumulative reports and payments relief option under § 204.202, your relief will terminate at the end of the calendar year in which you received the notice.</P> <P>(ii) If you were approved for prepayment relief under subpart B of this part or other relief under § 204.203, MMS's notice will tell you when your relief terminates.</P> <P>(2) MMS's decision to discontinue relief is not subject to administrative appeal.</P> </SECTION> <SECTION> <SECTNO>§ 204.6</SECTNO> <SUBJECT>May I appeal if MMS denies my request for prepayment or other relief?</SUBJECT> <P>If MMS denies your request for prepayment relief under Subpart B of this part or other relief under § 204.203, you may appeal under 30 CFR part 290.</P> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart B—Prepayment of Royalty [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Accounting and Auditing Relief</HD> <SECTION> <SECTNO>§ 204.200</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <P>This subpart explains how you as a lessee or designee may obtain accounting and auditing relief for your Federal onshore or OCS lease production from a marginal property. The two types of accounting and auditing relief that you can receive under this subpart are cumulative reports and payment relief (explained in § 204.202) and other accounting and auditing relief appropriate for your property (explained in § 204.203).</P> </SECTION> <SECTION> <SECTNO>§ 204.201</SECTNO> <SUBJECT>Who may obtain accounting and auditing relief?</SUBJECT> <P>(a) You may obtain accounting and auditing relief under this subpart:</P> <P>(1) If you are a lessee or a designee for a Federal lease with production from a property that qualifies as a marginal property under § 204.4;</P> <P>(2) If you meet any additional requirements for specific types of relief under this subpart; and</P> <P>(3) Only for the fractional interest in production from the marginal property for which you report and pay royalty. You may obtain relief even if the other lessees or designees for your lease or agreement do not request relief.</P> <P>(b) You may not obtain one or both of the relief options specified in this subpart on any portion of production from a marginal property if:</P> <P>(1) The marginal property covers multiple States; and</P> <P>(2) One of the States determines under § 204.208 that it will not allow the relief option you seek.</P> </SECTION> <SECTION> <SECTNO>§ 204.202</SECTNO> <SUBJECT>What is the cumulative royalty reports and payments relief option?</SUBJECT> <P>(a) The cumulative royalty reports and payments relief option allows you to submit one royalty report and payment annually for production during a calendar year. You are eligible for this option only if the total volume produced from the marginal property (not just your share of the production) is 1,000 BOE or less during the base period.</P> <P>(b) To use the cumulative royalty reports and payments relief option, you must do all of the following:</P> <P>(1) Notify MMS in writing by January 31 of the calendar year for which you begin taking your relief. See § 204.205(a) for what your notification must contain;</P> <P>(2) Submit your royalty report and payment in accordance with 30 CFR 218.51(g) by the end of February of the year following the calendar year for which you reported annually, unless you have an estimated payment on file. If you have an estimated payment on file, you must submit your royalty report and payment by the end of March of the year following the calendar year for which you reported annually;</P> <P>(3) Use the sales month prior to the month that you submit your annual report and payment under paragraph (b)(2) of this section on your Report of Sales and Royalty Remittance, Form MMS-2014, for the entire previous calendar year's production for which you are paying annually. (For example, for <PRTPAGE P="47"/>a report in February use January as your sales month, and for a report in March use February as your sales month, to report production for the entire previous calendar year for which you are paying annually);</P> <P>(4) Report one line of cumulative royalty information on Form MMS-2014 for the calendar year, the same as if it were a monthly report; and</P> <P>(5) Report allowances on Form MMS-2014 on the same annual basis as the royalties for your marginal property production.</P> <P>(c) If you do not pay your royalty by the date due in paragraph (b) of this section, you will owe late payment interest determined under 30 CFR 218.54 from the date your payment was due under this section until the date MMS receives it.</P> <P>(d) If you take relief you are not qualified for, you may be liable for civil penalties. Also you must:</P> <P>(1) Pay MMS late payment interest determined under 30 CFR 218.54 from the date your payment was due until the date MMS receives it; and</P> <P>(2) Amend your Form MMS-2014 to reflect the required monthly reporting.</P> <P>(e) If you dispose of your ownership interest in a marginal property for which you have taken relief under this section (or if you are a designee who reports and pays royalty for a lessee who has disposed of its ownership interest), you must:</P> <P>(1) Report and pay royalties for the portion of the calendar year for which you had an ownership interest; and</P> <P>(2) Make the report and payment by the end of the month after you dispose of the ownership interest in the marginal property. If you do not report and pay timely, you will owe interest determined under 30 CFR 218.54 from the date the payment was due under this section.</P> </SECTION> <SECTION> <SECTNO>§ 204.203</SECTNO> <SUBJECT>What is the other relief option?</SUBJECT> <P>(a) Under this relief option, you may request any type of accounting and auditing relief that is appropriate for production from your marginal property, provided it is not prohibited under § 204.204 and meets the statutory requirements of § 204.5. Examples of relief options you could request are:</P> <P>(1) To report and pay royalties using a valuation method other than that required under 30 CFR part 206 that approximates royalties payable under that part 206; and</P> <P>(2) To reduce your royalty audit burden. However, MMS will not consider any request that eliminates MMS's or the States' right to audit.</P> <P>(b) You must request approval from MMS under § 204.205(b), and receive approval under § 204.206 before taking relief under this option.</P> </SECTION> <SECTION> <SECTNO>§ 204.204</SECTNO> <SUBJECT>What accounting and auditing relief will MMS not allow?</SUBJECT> <P>MMS will not approve your request for accounting and auditing relief under this subpart if your request:</P> <P>(a) Prohibits MMS or the State from conducting any form of audit;</P> <P>(b) Permanently relieves you from making future royalty reports or payments;</P> <P>(c) Provides for less frequent royalty reports and payments than annually;</P> <P>(d) Provides for you to submit royalty reports and payments at separate times;</P> <P>(e) Impairs MMS's ability to properly or efficiently account for or distribute royalties;</P> <P>(f) Requests relief for a lease under which the Federal Government takes its royalties in kind;</P> <P>(g) Alters production reporting requirements;</P> <P>(h) Alters lease operation or safety requirements;</P> <P>(i) Conflicts with rent, minimum royalty, or lease requirements; or</P> <P>(j) Requests relief for production from a marginal property located in whole or in part in a State that has determined that it will not allow such relief under § 204.208.</P> </SECTION> <SECTION> <SECTNO>§ 204.205</SECTNO> <SUBJECT>How do I obtain accounting and auditing relief?</SUBJECT> <P>(a) To take cumulative reports and payments relief under § 204.202, you must notify MMS in writing by January 31 of the calendar year for which you begin taking your relief.</P> <P>(1) Your notification must contain:</P> <P>(i) Your company name, MMS-assigned payor code, address, phone number, and contact name; and<PRTPAGE P="48"/> </P> <P>(ii) The specific MMS lease number and agreement number, if applicable.</P> <P>(2) You may file a single notification for multiple marginal properties.</P> <P>(b) To obtain other relief under § 204.203, you must file a written request for relief with MMS.</P> <P>(1) Your request must contain:</P> <P>(i) Your company name, MMS-assigned payor code, address, phone number, and contact name;</P> <P>(ii) The MMS lease number and agreement number, if applicable; and</P> <P>(iii) A complete and detailed description of the specific accounting or auditing relief you seek.</P> <P>(2) You may file a single request for multiple marginal properties if you are requesting the same relief for all properties.</P> </SECTION> <SECTION> <SECTNO>§ 204.206</SECTNO> <SUBJECT>What will MMS do when it receives my request for other relief?</SUBJECT> <P>When MMS receives your request for other relief under § 204.205(b), it will notify you in writing as follows:</P> <P>(a) If your request for relief is complete, MMS may either approve, deny, or modify your request in writing after consultation with any State required under § 204.207(b).</P> <P>(1) If MMS approves your request for relief, MMS will notify you of the effective date of your accounting or auditing relief and other specifics of the relief approved.</P> <P>(2) If MMS denies your relief request, MMS will notify you of the reasons for denial and your appeal rights under § 204.6.</P> <P>(3) If MMS modifies your relief request, MMS will notify you of the modifications.</P> <P>(i) You have 60 days from your receipt of MMS's notice to either accept or reject any modification(s) in writing.</P> <P>(ii) If you reject the modification(s) or fail to respond to MMS's notice, MMS will deny your relief request. MMS will notify you in writing of the reasons for denial and your appeal rights under § 204.6.</P> <P>(b) If your request for relief is not complete, MMS will notify you in writing that your request is incomplete and identify any missing information.</P> <P>(1) You must submit the missing information within 60 days of your receipt of MMS's notice that your request is incomplete.</P> <P>(2) After you submit all required information, MMS may approve, deny, or modify your request for relief under paragraph (a) of this section.</P> <P>(3) If you do not submit all required information within 60 days of your receipt of MMS's notice that your request is incomplete, MMS will deny your relief request. MMS will notify you in writing of the reasons for denial and your appeal rights under § 204.6.</P> <P>(4) You may submit a new request for relief under this subpart at any time after MMS returns your incomplete request.</P> </SECTION> <SECTION> <SECTNO>§ 204.207</SECTNO> <SUBJECT>Who will approve, deny, or modify my request for accounting and auditing relief?</SUBJECT> <P>(a) If there is not a State concerned for your marginal property, only MMS will decide whether to approve, deny, or modify your relief request.</P> <P>(b) If there is a State concerned for your marginal property that has determined in advance under § 204.208 that it will allow either or both of the relief options under this subpart, MMS will decide whether to approve, deny, or modify your relief request after consulting with the State concerned.</P> </SECTION> <SECTION> <SECTNO>§ 204.208</SECTNO> <SUBJECT>May a State decide that it will or will not allow one or both of the relief options under this subpart?</SUBJECT> <P>(a) A State may decide in advance that it will or will not allow one or both of the relief options specified in this subpart for a particular calendar year. If a State decides that it will not consent to one or both of the relief options, MMS will not grant that type of marginal property relief.</P> <P>(b) To help States decide whether to allow one or both of the relief options specified in this subpart, for each calendar year MMS will send States a Report of Marginal Properties by October 1 preceding the calendar year.</P> <P>(c) If a State decides under paragraph (a) of this section that it will or will not allow one or both of the relief options in this subpart during the next calendar year, within 30 days of the State's receipt of the Report of Marginal Properties under paragraph (b) of this section, the State must:<PRTPAGE P="49"/> </P> <P>(1) Notify the Associate Director for Minerals Revenue Management, MMS, in writing, of its intent to allow or not allow one or both of the relief options under this subpart; and</P> <P>(2) Specify in its notice of intent to MMS which relief option(s) it will allow or not allow.</P> <P>(d) If a State decides in advance under paragraph (a) of this section that it will not allow one or both of the relief options specified in this subpart, it may decide for subsequent calendar years that it will allow one or both of the relief options in this subpart. If it so decides, within 30 days of the State's receipt of the Report of Marginal Properties under paragraph (b) of this section, the State must:</P> <P>(1) Notify the Associate Director for Minerals Revenue Management, MMS, in writing, of its intent to allow one or both of the relief options allowed under this subpart during the next calendar year; and</P> <P>(2) Specify in its notice of intent to MMS which relief option(s) it will allow.</P> <P>(e) If a State does not notify MMS under paragraph (c) or (d) of this section, the State will be deemed to have decided not to allow either of the relief options under this subpart for the next calendar year.</P> <P>(f) MMS will publish a notice of the State s intent to allow or not allow certain relief options under this section in the <E T="04">Federal Register</E> no later than 30 days before the beginning of the applicable calendar year.</P> </SECTION> <SECTION> <SECTNO>§ 204.209</SECTNO> <SUBJECT>What if a property ceases to qualify for relief obtained under this subpart?</SUBJECT> <P>(a) A marginal property must qualify for relief under this subpart for each calendar year based on production during the base period for that calendar year. The notice or request you provided to MMS under § 204.205 for the first calendar year that the property qualified for relief remains effective for successive calendar years if the property continues to qualify.</P> <P>(b) If a property is no longer eligible for relief for any reason during a calendar year other than the reason under § 204.210 or paragraph (c) of this section, the relief for the property terminates as of December 31 of that calendar year. You must notify MMS in writing by December 31 that the relief for the property has terminated.</P> <P>(c) If you dispose of your interest in a marginal property during the calendar year, your relief terminates as of the end of the sales month in which you disposed of the property. Report and pay royalties for your production using the procedures in § 204.202(e).</P> </SECTION> <SECTION> <SECTNO>§ 204.210</SECTNO> <SUBJECT>What if a property is approved as part of a nonqualifying agreement?</SUBJECT> <P>If the Bureau of Land Management (BLM) or MMS's Offshore Minerals Management (OMM) retroactively approves a marginal property that qualified for relief for inclusion as part of an agreement that does not qualify for relief under this subpart, the property no longer qualifies for relief under this subpart then:</P> <P>(a) MMS will not retroactively rescind the marginal property relief for production from your property under § 204.211;</P> <P>(b) Your marginal property relief terminates as of December 31 of the calendar year that you receive the BLM or OMM approval of your marginal property as part of a nonqualifying agreement; and</P> <P>(c) For the calendar year in which you receive the BLM or OMM approval, and for any previous period affected by the approval, the volumes on which you report and pay royalty for your lease must be amended to reflect all volumes produced on or allocated to your lease under the nonqualifying agreement as modified by BLM or OMM. Report and pay royalties for your production using the procedures in § 204.202(b).</P> <P>(d) If you owe additional royalties based on the retroactive agreement approval and do not pay your royalty by the date due in § 204.202(b), you will owe late payment interest determined under 30 CFR 218.54 from the date your payment was due under § 204.202 (b)(2) until the date MMS receives it.</P> </SECTION> <SECTION> <PRTPAGE P="50"/> <SECTNO>§ 204.211</SECTNO> <SUBJECT>When may MMS rescind relief for a property?</SUBJECT> <P>(a) MMS may retroactively rescind the relief for your property if MMS determines that your property was not eligible for the relief obtained under this subpart because:</P> <P>(1) You did not submit a notice or request for relief under § 204.205;</P> <P>(2) You submitted erroneous information in the notice or request for relief you provided to MMS under § 204.205 or in your royalty or production reports; or</P> <P>(3) Your property is no longer eligible for relief because production increased, but you failed to provide the notice required under § 204.209(b).</P> <P>(b) MMS may rescind relief for your property if MMS decides to take royalty in kind.</P> </SECTION> <SECTION> <SECTNO>§ 204.212</SECTNO> <SUBJECT>What if I took relief for which I was ineligible?</SUBJECT> <P>If you took relief under this subpart for a period for which you were not eligible, you:</P> <P>(a) May owe additional royalties and late payment interest determined under 30 CFR 218.54 from the date your additional payments were due until the date MMS receives them; and</P> <P>(b) May be subject to civil penalties.</P> </SECTION> <SECTION> <SECTNO>§ 204.213</SECTNO> <SUBJECT>May I obtain relief for a property that benefits from other Federal or State incentive programs?</SUBJECT> <P>You may obtain accounting and auditing relief for production from a marginal property under this subpart even if the property benefits from other Federal or State production incentive programs.</P> </SECTION> <SECTION> <SECTNO>§ 204.214</SECTNO> <SUBJECT>Is minimum royalty due on a property for which I took relief?</SUBJECT> <P>(a) If you took cumulative royalty reports and payment relief on a property under this subpart, minimum royalty is still due for that property by the date prescribed in your lease and in the amount prescribed therein.</P> <P>(b) If you pay minimum royalty on production from a marginal property during a calendar year for which you are taking cumulative royalty reports and payment relief, and:</P> <P>(1) The annual payment you owe under this subpart is greater than the minimum royalty you paid, you must pay the difference between the minimum royalty you paid and your annual payment due under this subpart; or</P> <P>(2) The annual payment you owe under this subpart is less than the minimum royalty you paid, you are not entitled to a credit because you must pay at least the minimum royalty amount on your lease each year.</P> </SECTION> <SECTION> <SECTNO>§ 204.215</SECTNO> <SUBJECT>Are the information collection requirements in this subpart approved by the Office of Management and Budget (OMB)?</SUBJECT> <P>OMB has approved the information collection requirements contained in this subpart under 44 U.S.C. 3501 <E T="03">et seq.</E>, and assigned OMB control number 1010-0155. See 30 CFR part 210 for details concerning your estimated reporting burden and how you may comment on the accuracy of the burden estimate.</P> </SECTION> </SUBPART> </PART> <PART> <EAR>Pt. 206</EAR> <HD SOURCE="HED">PART 206—PRODUCT VALUATION</HD> <CONTENTS> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECHD>Sec.</SECHD> <SECTNO>206.10</SECTNO> <SUBJECT>Information collection.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Indian Oil</HD> <SECTNO>206.50</SECTNO> <SUBJECT>Purpose and scope.</SUBJECT> <SECTNO>206.51</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>206.52</SECTNO> <SUBJECT>Valuation standards.</SUBJECT> <SECTNO>206.53</SECTNO> <SUBJECT>Point of royalty settlement.</SUBJECT> <SECTNO>206.54</SECTNO> <SUBJECT>Transportation allowances—general.</SUBJECT> <SECTNO>206.55</SECTNO> <SUBJECT>Determination of transportation allowances.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Federal Oil</HD> <SECTNO>206.100 </SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <SECTNO>206.101 </SECTNO> <SUBJECT>What definitions apply to this subpart?</SUBJECT> <SECTNO>206.102 </SECTNO> <SUBJECT>How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm's-length contract?</SUBJECT> <SECTNO>206.103 </SECTNO> <SUBJECT>How do I value oil that is not sold under an arm's-length contract?</SUBJECT> <SECTNO>206.104 </SECTNO> <SUBJECT>What publications are acceptable to MMS?</SUBJECT> <SECTNO>206.105 </SECTNO> <SUBJECT>What records must I keep to support my calculations of value under this subpart?</SUBJECT> <SECTNO>206.106 </SECTNO> <SUBJECT>What are my responsibilities to place production into marketable condition and to market production?</SUBJECT> <SECTNO>206.107 </SECTNO> <SUBJECT>How do I request a value determination?<PRTPAGE P="51"/> </SUBJECT> <SECTNO>206.108</SECTNO> <SUBJECT>Does MMS protect information I provide?</SUBJECT> <SECTNO>206.109</SECTNO> <SUBJECT>When may I take a transportation allowance in determining value?</SUBJECT> <SECTNO>206.110</SECTNO> <SUBJECT>How do I determine a transportation allowance under an arm's-length transportation contract?</SUBJECT> <SECTNO>206.111</SECTNO> <SUBJECT>How do I determine a transportation allowance if I do not have an arm's-length transportation contract or arm's-length tariff?</SUBJECT> <SECTNO>206.112</SECTNO> <SUBJECT>What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices?</SUBJECT> <SECTNO>206.113</SECTNO> <SUBJECT>How will MMS identify market centers?</SUBJECT> <SECTNO>206.114</SECTNO> <SUBJECT>What are my reporting requirements under an arm's-length transportation contract?</SUBJECT> <SECTNO>206.115</SECTNO> <SUBJECT>What are my reporting requirements under a non-arm's-length transportation arrangement?</SUBJECT> <SECTNO>206.116 </SECTNO> <SUBJECT>What interest and assessments apply if I improperly report a transportation allowance?</SUBJECT> <SECTNO>206.117 </SECTNO> <SUBJECT>What reporting adjustments must I make for transportation allowances?</SUBJECT> <SECTNO>206.119 </SECTNO> <SUBJECT>How are the royalty quantity and quality determined?</SUBJECT> <SECTNO>206.120 </SECTNO> <SUBJECT>How are operating allowances determined?</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart D—Federal Gas</HD> <SECTNO>206.150</SECTNO> <SUBJECT>Purpose and scope.</SUBJECT> <SECTNO>206.151</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>206.152</SECTNO> <SUBJECT>Valuation standards—unprocessed gas.</SUBJECT> <SECTNO>206.153</SECTNO> <SUBJECT>Valuation standards—processed gas.</SUBJECT> <SECTNO>206.154</SECTNO> <SUBJECT>Determination of quantities and qualities for computing royalties.</SUBJECT> <SECTNO>206.155</SECTNO> <SUBJECT>Accounting for comparison.</SUBJECT> <SECTNO>206.156</SECTNO> <SUBJECT>Transportation allowances—general.</SUBJECT> <SECTNO>206.157</SECTNO> <SUBJECT>Determination of transportation allowances.</SUBJECT> <SECTNO>206.158</SECTNO> <SUBJECT>Processing allowances—general.</SUBJECT> <SECTNO>206.159</SECTNO> <SUBJECT>Determination of processing allowances.</SUBJECT> <SECTNO>206.160</SECTNO> <SUBJECT>Operating allowances.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Indian Gas</HD> <SECTNO>206.170</SECTNO> <SUBJECT>What does this subpart contain?</SUBJECT> <SECTNO>206.171</SECTNO> <SUBJECT>What definitions apply to this subpart?</SUBJECT> <SECTNO>206.172</SECTNO> <SUBJECT>How do I value gas produced from leases in an index zone?</SUBJECT> <SECTNO>206.173</SECTNO> <SUBJECT>How do I calculate the alternative methodology for dual accounting?</SUBJECT> <SECTNO>206.174</SECTNO> <SUBJECT>How do I value gas production when an index-based method cannot be used?</SUBJECT> <SECTNO>206.175</SECTNO> <SUBJECT>How do I determine quantities and qualities of production for computing royalties?</SUBJECT> <SECTNO>206.176</SECTNO> <SUBJECT>How do I perform accounting for comparison?</SUBJECT> <SUBJGRP> <HD SOURCE="HED">Transportation Allowances</HD> <SECTNO>206.177</SECTNO> <SUBJECT>What general requirements regarding transportation allowances apply to me?</SUBJECT> <SECTNO>206.178</SECTNO> <SUBJECT>How do I determine a transportation allowance?</SUBJECT> </SUBJGRP> <SUBJGRP> <HD SOURCE="HED">Processing Allowances</HD> <SECTNO>206.179</SECTNO> <SUBJECT>What general requirements regarding processing allowances apply to me?</SUBJECT> <SECTNO>206.180</SECTNO> <SUBJECT>How do I determine an actual processing allowance?</SUBJECT> <SECTNO>206.181</SECTNO> <SUBJECT>How do I establish processing costs for dual accounting purposes when I do not process the gas?</SUBJECT> </SUBJGRP> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Federal Coal</HD> <SECTNO>206.250</SECTNO> <SUBJECT>Purpose and scope.</SUBJECT> <SECTNO>206.251</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>206.252</SECTNO> <SUBJECT>Information collection.</SUBJECT> <SECTNO>206.253</SECTNO> <SUBJECT>Coal subject to royalties—general provisions.</SUBJECT> <SECTNO>206.254</SECTNO> <SUBJECT>Quality and quantity measurement standards for reporting and paying royalties.</SUBJECT> <SECTNO>206.255</SECTNO> <SUBJECT>Point of royalty determination.</SUBJECT> <SECTNO>206.256</SECTNO> <SUBJECT>Valuation standards for cents-per-ton leases.</SUBJECT> <SECTNO>206.257</SECTNO> <SUBJECT>Valuation standards for ad valorem leases.</SUBJECT> <SECTNO>206.258</SECTNO> <SUBJECT>Washing allowances—general.</SUBJECT> <SECTNO>206.259</SECTNO> <SUBJECT>Determination of washing allowances.</SUBJECT> <SECTNO>206.260</SECTNO> <SUBJECT>Allocation of washed coal.</SUBJECT> <SECTNO>206.261</SECTNO> <SUBJECT>Transportation allowances—general.</SUBJECT> <SECTNO>206.262</SECTNO> <SUBJECT>Determination of transportation allowances.</SUBJECT> <SECTNO>206.263</SECTNO> <SUBJECT>[Reserved]</SUBJECT> <SECTNO>206.264</SECTNO> <SUBJECT>In-situ and surface gasification and liquefaction operations.</SUBJECT> <SECTNO>206.265</SECTNO> <SUBJECT>Value enhancement of marketable coal.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart G—Other Solid Minerals</HD> <SECTNO>206.301</SECTNO> <SUBJECT>Value basis for royalty computation.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Geothermal Resources</HD> <SECTNO>206.350</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <SECTNO>206.351</SECTNO> <SUBJECT>What definitions apply to this subpart?</SUBJECT> <SECTNO>206.352</SECTNO> <SUBJECT>How do I calculate the royalty due on geothermal resources used for commercial production or generation of electricity?</SUBJECT> <SECTNO>206.353</SECTNO> <SUBJECT>How do I determine transmission deductions?</SUBJECT> <SECTNO>206.354</SECTNO> <SUBJECT>How do I determine generating deductions?</SUBJECT> <SECTNO>206.355</SECTNO> <SUBJECT>How do I calculate royalty due on geothermal resources I sell at arm's length to a purchaser for direct use?</SUBJECT> <SECTNO>206.356</SECTNO> <SUBJECT>How do I calculate royalty due on geothermal resources I use for direct use purposes?<PRTPAGE P="52"/> </SUBJECT> <SECTNO>206.357</SECTNO> <SUBJECT>How do I calculate royalty due on byproducts?</SUBJECT> <SECTNO>206.358</SECTNO> <SUBJECT>What are byproduct transportation allowances?</SUBJECT> <SECTNO>206.359</SECTNO> <SUBJECT>How do I determine byproduct transportation allowances?</SUBJECT> <SECTNO>206.360</SECTNO> <SUBJECT>What records must I keep to support my calculations of royalty or fees under this subpart?</SUBJECT> <SECTNO>206.361</SECTNO> <SUBJECT>How will MMS determine whether my royalty or direct use fee payments are correct?</SUBJECT> <SECTNO>206.362</SECTNO> <SUBJECT>What are my responsibilities to place production into marketable condition and to market production?</SUBJECT> <SECTNO>206.363</SECTNO> <SUBJECT>When is an MMS audit, review, reconciliation, monitoring, or other like process considered final?</SUBJECT> <SECTNO>206.364</SECTNO> <SUBJECT>How do I request a value or gross proceeds determination?</SUBJECT> <SECTNO>206.365</SECTNO> <SUBJECT>Does MMS protect information I provide?</SUBJECT> <SECTNO>206.366</SECTNO> <SUBJECT>What is the nominal fee that a State, tribal, or local government lessee must pay for the use of geothermal resources?</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart J—Indian Coal</HD> <SECTNO>206.450</SECTNO> <SUBJECT>Purpose and scope.</SUBJECT> <SECTNO>206.451</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>206.452</SECTNO> <SUBJECT>Coal subject to royalties—general provisions.</SUBJECT> <SECTNO>206.453</SECTNO> <SUBJECT>Quality and quantity measurement standards for reporting and paying royalties.</SUBJECT> <SECTNO>206.454</SECTNO> <SUBJECT>Point of royalty determination.</SUBJECT> <SECTNO>206.455</SECTNO> <SUBJECT>Valuation standards for cents-per-ton leases.</SUBJECT> <SECTNO>206.456</SECTNO> <SUBJECT>Valuation standards for ad valorem leases.</SUBJECT> <SECTNO>206.457</SECTNO> <SUBJECT>Washing allowances—general.</SUBJECT> <SECTNO>206.458</SECTNO> <SUBJECT>Determination of washing allowances.</SUBJECT> <SECTNO>206.459</SECTNO> <SUBJECT>Allocation of washed coal.</SUBJECT> <SECTNO>206.460</SECTNO> <SUBJECT>Transportation allowances—general.</SUBJECT> <SECTNO>206.461</SECTNO> <SUBJECT>Determination of transportation allowances.</SUBJECT> <SECTNO>206.462</SECTNO> <SUBJECT>[Reserved]</SUBJECT> <SECTNO>206.463</SECTNO> <SUBJECT>In-situ and surface gasification and liquefaction operations.</SUBJECT> <SECTNO>206.464</SECTNO> <SUBJECT>Value enhancement of marketable coal.</SUBJECT> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>5 U.S.C. 301 <E T="03">et seq.;</E> 25 U.S.C. 396 <E T="03">et seq.,</E> 396a <E T="03">et seq.,</E> 2101 <E T="03">et seq.;</E> 30 U.S.C. 181 <E T="03">et seq.,</E> 351 <E T="03">et seq.,</E> 1001 <E T="03">et seq.,</E> 1701 <E T="03">et seq.;</E> 31 U.S.C. 9701.; 43 U.S.C. 1301 <E T="03">et seq.,</E> 1331 <E T="03">et seq.,</E> and 1801 <E T="03">et seq.</E> </P> </AUTH> <EDNOTE> <HD SOURCE="HED">Editorial Note:</HD> <P>Nomenclature changes to part 206 appear at 67 FR 19111, Apr. 18, 2002.</P> </EDNOTE> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECTION> <SECTNO>§ 206.10</SECTNO> <SUBJECT>Information collection.</SUBJECT> <P>The information collection requirements contained in this part have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 <E T="03">et seq.</E> The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10.</P> <CITA>[57 FR 41863, Sept. 14, 1992]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Indian Oil</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>61 FR 5455, Feb. 12, 1996, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 206.50</SECTNO> <SUBJECT>Purpose and scope.</SUBJECT> <P>(a) This subpart is applicable to all oil production from Indian (Tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma). The purpose of this subpart is to establish the value of production, for royalty purposes, consistent with the mineral leasing laws, other applicable laws, and lease terms.</P> <P>(b) If the specific provisions of any Federal statute, treaty, settlement agreement between the Indian lessor and a lessee resulting from administrative or judicial litigation, or oil and gas lease subject to the requirements of this subpart are inconsistent with any regulation in this subpart, then the statute, treaty, lease provision or settlement agreement shall govern to the extent of that inconsistency.</P> <P>(c) All royalty payments made to MMS or Indian Tribes are subject to audit and adjustment.</P> <P>(d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian oil and gas leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.</P> </SECTION> <SECTION> <SECTNO>§ 206.51</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>For the purposes of this subpart:</P> <P> <E T="03">Allowance</E> means an approved or an MMS-initially accepted deduction in determining value for royalty purposes. Transportation allowance means an allowance for the reasonable, actual <PRTPAGE P="53"/>costs incurred by the lessee for moving oil to a point of sale or point of delivery off the lease, unit area, or communitized area, excluding gathering, or an approved or MMS-initially accepted deduction for costs of such transportation, determined by this subpart.</P> <P> <E T="03">Area</E> means a geographic region at least as large as the defined limits of an oil and/or gas field in which oil and/or gas lease products have similar quality, economic, and legal characteristics.</P> <P> <E T="03">Arm's-length contract</E> means a contract or agreement that has been arrived at in the market place between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership: ownership in excess of 50 percent constitutes control; ownership of 10 through 50 percent creates a presumption of control; and ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. MMS may require the lessee to certify ownership control. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month, as well as when the contract was executed.</P> <P> <E T="03">Audit</E> means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Indian leases.</P> <P> <E T="03">BIA</E> means the Bureau of Indian Affairs of the Department of the Interior.</P> <P> <E T="03">BLM</E> means the Bureau of Land Management of the Department of the Interior.</P> <P> <E T="03">Condensate</E> means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.</P> <P> <E T="03">Contract</E> means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.</P> <P> <E T="03">Field</E> means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields are usually given names and their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located.</P> <P> <E T="03">Gathering</E> means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area, or to a central accumulation or treatment point off the lease, unit, or communitized area as approved by BLM operations personnel for onshore leases.</P> <P> <E T="03">Gross proceeds</E> (for royalty payment purposes) means the total monies and other consideration accruing to an oil and gas lessee for the disposition of the oil produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as dehydration, measurement, and/or gathering to the extent that the lessee is obligated to perform them at no cost to the Indian lessor. Gross proceeds, as applied to oil, also includes, but is not limited to, reimbursements for harboring or terminaling fees. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Indian royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it <PRTPAGE P="54"/>does not seek to collect through reasonable efforts are also part of gross proceeds.</P> <P> <E T="03">Indian allottee</E> means any Indian for whom land or an interest in land is held in trust by the United States or who holds title subject to Federal restriction against alienation.</P> <P> <E T="03">Indian Tribe</E> means any Indian Tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any land or interest in land is held in trust by the United States or which is subject to Federal restriction against alienation.</P> <P> <E T="03">Lease</E> means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products—or the land area covered by that authorization, whichever is required by the context.</P> <P> <E T="03">Lease products</E> means any leased minerals attributable to, originating from, or allocated to Indian leases.</P> <P> <E T="03">Lessee</E> means any person to whom an Indian Tribe, or an Indian allottee issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.</P> <P> <E T="03">Like-quality lease products</E> means lease products which have similar chemical, physical, and legal characteristics.</P> <P> <E T="03">Load oil</E> means any oil which has been used with respect to the operation of oil or gas wells for wellbore stimulation, workover, chemical treatment, or production purposes. It does not include oil used at the surface to place lease production in marketable condition.</P> <P> <E T="03">Marketable condition</E> means lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.</P> <P> <E T="03">Marketing affiliate</E> means an affiliate of the lessee whose function is to acquire only the lessee's production and to market that production.</P> <P> <E T="03">Minimum royalty</E> means that minimum amount of annual royalty that the lessee must pay as specified in the lease or in applicable leasing regulations.</P> <P> <E T="03">MMS</E> means the Minerals Management Service of the Department of the Interior.</P> <P> <E T="03">Net-back method</E> (or workback method) means a method for calculating market value of oil at the lease. Under this method, costs of transportation, processing, or manufacturing are deducted from the proceeds received for the oil and any extracted, processed, or manufactured products, or from the value of the oil or any extracted, processed, or manufactured products at the first point at which reasonable values for any such products may be determined by a sale under an arm's-length contract or comparison to other sales of such products, to ascertain value at the lease.</P> <P> <E T="03">Net profit share</E> (for applicable Indian lessees) means the specified share of the net profit from production of oil and gas as provided in the agreement.</P> <P> <E T="03">Oil</E> means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and is marketed or used as such. Condensate recovered in lease separators or field facilities is considered to be oil. For purposes of royalty valuation, the term tar sands is defined separately from oil.</P> <P> <E T="03">Oil shale</E> means a kerogen-bearing rock (<E T="03">i.e.</E>, fossilized, insoluble, organic material). Separation of kerogen from oil shale may take place in situ or in surface retorts by various processes. The kerogen, upon distillation, will yield liquid and gaseous hydrocarbons.</P> <P> <E T="03">Person</E> means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).</P> <P> <E T="03">Posted price</E> means the price specified in publicly available posted price bulletins, onshore terminal postings, or other price notices net of all adjustments for quality (e.g., API gravity, sulfur content, etc.) and location for oil in marketable condition.<PRTPAGE P="55"/> </P> <P> <E T="03">Processing</E> means any process designed to remove elements or compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes which normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, and compression are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.</P> <P> <E T="03">Selling arrangement</E> means the individual contractual arrangements under which sales or dispositions of oil are made. Selling arrangements are described by illustration in MMS Royalty Management Program Oil and Gas Payor Handbook.</P> <P> <E T="03">Spot sales agreement</E> means a contract wherein a seller agrees to sell to a buyer a specified amount of oil at a specified price over a fixed period, usually of short duration, which does not normally require a cancellation notice to terminate, and which does not contain an obligation, nor imply an intent, to continue in subsequent periods.</P> <P> <E T="03">Tar sands</E> means any consolidated or unconsolidated rock (other than coal, oil shale, or gilsonite) that contains a hydrocarbonaceous material with a gas-free viscosity greater than 10,000 centipoise at original reservoir temperature.</P> <CITA>[61 FR 5455, Feb. 12, 1996, as amended at 64 FR 43288, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.52</SECTNO> <SUBJECT>Valuation standards.</SUBJECT> <P>(a)(1) The value of production, for royalty purposes, of oil from leases subject to this subpart shall be the value determined under this section less applicable allowances determined under this subpart.</P> <P>(2)(i) For any Indian leases which provide that the Secretary may consider the highest price paid or offered for a major portion of production (major portion) in determining value for royalty purposes, if data are available to compute a major portion, MMS will, where practicable, compare the value determined in accordance with this section with the major portion. The value to be used in determining the value of production, for royalty purposes, shall be the higher of those two values.</P> <P>(ii) For purposes of this paragraph, major portion means the highest price paid or offered at the time of production for the major portion of oil production from the same field. The major portion will be calculated using like-quality oil sold under arm's-length contracts from the same field (or, if necessary to obtain a reasonable sample, from the same area) for each month. All such oil production will be arrayed from highest price to lowest price (at the bottom).</P> <P>The major portion is that price at which 50 percent (by volume) plus 1 barrel of the oil (starting from the bottom) is sold.</P> <P>(b)(1)(i) The value of oil which is sold under an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii) and (b)(1)(iii) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit. For purposes of this section, oil which is sold or otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate under an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate.</P> <P>(ii) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the oil. If the contract does not reflect the total consideration, then MMS may require that the oil sold under that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration.</P> <P>(iii) If MMS determines that the gross proceeds accruing to the lessee under an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between two contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of <PRTPAGE P="56"/>the lessee and the lessor, then MMS shall require that the oil production be valued under the first applicable of paragraph (c)(2), (c)(3), (c)(4), or (c)(5) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's value. If the oil production is then valued under paragraph (c)(4) or (c)(5) of this section, the notification requirements of paragraph (e) of this section shall apply.</P> <P>(2) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the oil.</P> <P>(c) The value of oil production from leases subject to this section which is not sold under an arm's-length contract shall be the reasonable value determined in accordance with the first applicable of the following paragraphs:</P> <P>(1) The lessee's contemporaneous posted prices or oil sales contract prices used in arm's-length transactions for purchases or sales of significant quantities of like-quality oil in the same field (or, if necessary to obtain a reasonable sample, from the same area); provided, however, that those posted prices or oil sales contract prices are comparable to other contemporaneous posted prices or oil sales contract prices used in arm's-length transactions for purchases or sales of significant quantities of like-quality oil in the same field (or, if necessary to obtain a reasonable sample, from the same area). In evaluating the comparability of posted prices or oil sales contract prices, the following factors shall be considered: Price, duration, market or markets served, terms, quality of oil, volume, and other factors as may be appropriate to reflect the value of the oil. If the lessee makes arm's-length purchases or sales at different postings or prices, then the volume-weighted average price for the purchases or sales for the production month will be used;</P> <P>(2) The arithmetic average of contemporaneous posted prices used in arm's-length transactions by persons other than the lessee for purchases or sales of significant quantities of like-quality oil in the same field (or, if necessary to obtain a reasonable sample, from the same area);</P> <P>(3) The arithmetic average of other contemporaneous arm's-length contract prices for purchases or sales of significant quantities of like-quality oil in the same area or nearby areas;</P> <P>(4) Prices received for arm's-length spot sales of significant quantities of like-quality oil from the same field (or, if necessary to obtain a reasonable sample, from the same area), and other relevant matters, including information submitted by the lessee concerning circumstances unique to a particular lease operation or the salability of certain types of oil;</P> <P>(5) A net-back method or any other reasonable method to determine value;</P> <P>(6) For purposes of this paragraph, the term lessee includes the lessee's designated purchasing agent, and the term contemporaneous means postings or contract prices in effect at the time the royalty obligation is incurred.</P> <P>(d) Any Indian lessee will make available, upon request to the authorized MMS or Indian representatives, to the Office of the Inspector General of the Department of the Interior, or other persons authorized to receive such information, arm's-length sales and volume data for like-quality production sold, purchased, or otherwise obtained by the lessee from the field or area or from nearby fields or areas.</P> <P>(e)(1) Where the value is determined under paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.</P> <P>(2) A lessee shall notify MMS if it has determined value under paragraph (c)(4) or (c)(5) of this section. The notification shall be by letter to MMS Associate Director for Minerals Revenue Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the <PRTPAGE P="57"/>month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c)(4) or (c)(5) of this section and each time there is a change from one to the other of these two methods.</P> <P>(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest on the difference computed under 30 CFR 218.54. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.</P> <P>(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method and may use that value for royalty payment purposes until MMS issues a value determination. The lessee shall submit all available data relevant to its proposal. MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination, MMS may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.</P> <P>(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production, for royalty purposes, be less than the gross proceeds accruing to the lessee for lease production, less applicable allowances determined under this subpart.</P> <P>(i) The lessee is required to place oil in marketable condition at no cost to the Indian lessor unless otherwise provided in the lease agreement or this section. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the oil in marketable condition.</P> <P>(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of oil.</P> <P>(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Indian Tribes or allottees until the audit period is formally closed.</P> <P>(l) Certain information submitted to MMS to support valuation proposals, including transportation allowances or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable laws and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. Nothing in this section is intended to limit or diminish in any manner whatsoever the right of an Indian lessor to obtain any and all information to which such lessor may be <PRTPAGE P="58"/>lawfully entitled from MMS or such lessor's lessee directly under the terms of the lease, 30 U.S.C. 1733, or other applicable law.</P> </SECTION> <SECTION> <SECTNO>§ 206.53</SECTNO> <SUBJECT>Point of royalty settlement.</SUBJECT> <P>(a)(1) Royalties shall be computed on the quantity and quality of oil as measured at the point of settlement approved by BLM for onshore leases.</P> <P>(2) If the value of oil determined under § 206.52 of this subpart is based upon a quantity and/or quality different from the quantity and/or quality at the point of royalty settlement approved by the BLM for onshore leases, the value shall be adjusted for those differences in quantity and/or quality.</P> <P>(b) No deductions may be made from the royalty volume or royalty value for actual or theoretical losses. Any actual loss that may be sustained prior to the royalty settlement metering or measurement point will not be subject to royalty provided that such actual loss is determined to have been unavoidable by BLM.</P> <P>(c) Except as provided in paragraph (b) of this section, royalties are due on 100 percent of the volume measured at the approved point of royalty settlement. There can be no reduction in that measured volume for actual losses beyond the approved point of royalty settlement or for theoretical losses that are claimed to have taken place either prior to or beyond the approved point of royalty settlement. Royalties are due on 100 percent of the value of the oil as provided in this subpart. There can be no deduction from the value of the oil for royalty purposes to compensate for actual losses beyond the approved point of royalty settlement or for theoretical losses that are claimed to have taken place either prior to or beyond the approved point of royalty settlement.</P> <CITA>[61 FR 5455, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.54</SECTNO> <SUBJECT>Transportation allowances—general.</SUBJECT> <P>(a) Where the value of oil has been determined under Section 206.52 of this subpart at a point (e.g., sales point or point of value determination) off the lease, MMS shall allow a deduction for the reasonable, actual costs incurred by the lessee to transport oil to a point off the lease; provided, however, that no transportation allowance will be granted for transporting oil taken as Royalty-In-Kind (RIK); or</P> <P>(b)(1) Except as provided in paragraph (b)(2) of this section, the transportation allowance deduction on the basis of a selling arrangement shall not exceed 50 percent of the value of the oil at the point of sale as determined under § 206.52 of this subpart. Transportation costs cannot be transferred between selling arrangements or to other products.</P> <P>(2) Upon request of a lessee, MMS may approve a transportation allowance deduction in excess of the limitation prescribed by paragraph (b)(1) of this section. The lessee must demonstrate that the transportation costs incurred in excess of the limitation prescribed in paragraph (b)(1) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) shall contain all relevant and supporting documentation necessary for MMS to make a determination. Under no circumstances shall the value, for royalty purposes, under any selling arrangement, be reduced to zero.</P> <P>(c) Transportation costs must be allocated among all products produced and transported as provided in § 206.55. Transportation allowances for oil shall be expressed as dollars per barrel.</P> <P>(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this subpart, then the lessee shall pay any additional royalties, plus interest determined in accordance with 30 CFR 218.54, or shall be entitled to a credit, without interest.</P> </SECTION> <SECTION> <SECTNO>§ 206.55</SECTNO> <SUBJECT>Determination of transportation allowances.</SUBJECT> <P>(a) <E T="03">Arm's-length transportation contracts.</E> (1)(i) For transportation costs incurred by a lessee under an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting oil under that contract, except as provided in paragraphs (a)(1)(ii) and <PRTPAGE P="59"/>(a)(1)(iii) of this section, subject to monitoring, review, audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. Such allowances shall be subject to the provisions of paragraph (f) of this section. Before any deduction may be taken, the lessee must submit a completed page one of Form MMS-4110 (and Schedule 1), Oil Transportation Allowance Report, in accordance with paragraph (c)(1) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4110 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee.</P> <P>(ii) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration, then MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.</P> <P>(iii) If MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.</P> <P>(2)(i) If an arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then the total transportation costs shall be allocated in a consistent and equitable manner to each of the liquid products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value). Except as provided in this paragraph, no allowance may be taken for the costs of transporting lease production which is not royalty-bearing without MMS approval.</P> <P>(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.</P> <P>(3) If an arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use the oil transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all available data to support its proposal. The initial proposal must be submitted by June 30, 1988 or within 3 months after the last day of the month for which the lessee requests a transportation allowance, whichever is later (unless MMS approves a longer period). MMS shall then determine the oil transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary.</P> <P>(4) Where the lessee's payments for transportation under an arm's-length contract are not on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.</P> <P>(5) Where an arm's-length sales contract price, or a posted price, includes a provision whereby the listed price is reduced by a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. The transportation factor may be used in determining the lessee's gross proceeds for the sale of the product. The transportation factor may not <PRTPAGE P="60"/>exceed 50 percent of the base price of the product without MMS approval.</P> <P>(b) <E T="03">Non-arm's-length or no contract.</E> (1) If a lessee has a non-arm's-length transportation contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable, actual costs as provided in this paragraph. All transportation allowances deducted under a non-arms-length or no-contract situation are subject to monitoring, review, audit, and adjustment. Before any estimated or actual deduction may be taken, the lessee must submit a completed Form MMS-4110 in its entirety in accordance with paragraph (c)(2) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4110 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee. MMS will monitor the allowance deductions to determine whether lessees are taking deductions that are reasonable and allowable. When necessary or appropriate, MMS may direct a lessee to modify its actual transportation allowance deduction.</P> <P>(2) The transportation allowance for non-arms-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial capital investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.</P> <P>(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.</P> <P>(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.</P> <P>(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of MMS.</P> <P>(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services or on a unit-of-production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.</P> <P>(B) MMS shall allow as a cost an amount equal to the initial capital investment in the transportation system multiplied by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service after March 1, 1988.</P> <P>(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and shall be effective <PRTPAGE P="61"/>during the reporting period. The rate shall be redetermined at the beginning of each subsequent transportation allowance reporting period (which is determined under paragraph (c) of this section).</P> <P>(3)(i) The deduction for transportation costs shall be determined on the basis of the lessee's cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, allocation of costs to each of the liquid products transported shall be in the same proportion as the ratio of the volume of each liquid product (excluding waste products which have no value) to the volume of all liquid products (excluding waste products which have no value) and such allocation shall be made in a consistent and equitable manner. Except as provided in this paragraph, the lessee may not take an allowance for transporting lease production which is not royalty-bearing without MMS approval.</P> <P>(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.</P> <P>(4) Where both gaseous and liquid products are transported through the same transportation system, the lessee shall propose a cost allocation procedure to MMS. The lessee may use the oil transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all available data to support its proposal. The initial proposal must be submitted by June 30, 1988 or within 3 months after the last day of the month for which the lessee requests a transportation allowance, whichever is later (unless MMS approves a longer period). MMS shall then determine the oil transportation allowance on the basis of the lessee's proposal and any additional information MMS deems necessary.</P> <P>(5) A lessee may apply to MMS for an exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) through (b)(4) of this section. MMS will grant the exception only if the lessee has a tariff for the transportation system approved by the Federal Energy Regulatory Commission (FERC) for Indian leases. MMS shall deny the exception request if it determines that the tariff is excessive as compared to arm's-length transportation charges by pipelines, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:</P> <P>(i) No FERC cost analysis exists and the FERC has declined to investigate under MMS timely objections upon filing; and</P> <P>(ii) the tariff significantly exceeds the lessee's actual costs for transportation as determined under this section.</P> <P>(c) <E T="03">Reporting requirements</E>—(1) <E T="03">Arm's-length contracts.</E> (i) With the exception of those transportation allowances specified in paragraphs (c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page one of the initial Form MMS-4110 (and Schedule 1), Oil Transportation Allowance Report, prior to, or at the same time as, the transportation allowance determined, under an arm's-length contract, is reported on Form MMS-2014, Report of Sales and Royalty Remittance. A Form MMS-4110 received by the end of the month that the Form MMS-2014 is due shall be considered to be timely received.</P> <P>(ii) The initial Form MMS-4110 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.</P> <P>(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4110 (and Schedule 1) within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during <PRTPAGE P="62"/>which period the lessee shall continue to use the allowance from the previous reporting period).</P> <P>(iv) MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.</P> <P>(v) Transportation allowances which are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.</P> <P>(vi) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.</P> <P>(2) <E T="03">Non-arm's-length or no contract.</E> (i) With the exception of those transportation allowances specified in paragraphs (c)(2)(v), (c)(2)(vii) and (c)(2)(viii) of this section, the lessee shall submit an initial Form MMS-4110 prior to, or at the same time as, the transportation allowance determined under a non-arm's-length contract or no-contract situation is reported on Form MMS-2014. A Form MMS-4110 received by the end of the month that the Form MMS-2014 is due shall be considered to be timely received. The initial report may be based upon estimated costs.</P> <P>(ii) The initial Form MMS-4110 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until transportation under the non-arm's-length contract or the no-contract situation terminates, whichever is earlier.</P> <P>(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4110 containing the actual costs for the previous reporting period. If oil transportation is continuing, the lessee shall include on Form MMS-4110 its estimated costs for the next calendar year. The estimated oil transportation allowance shall be based on the actual costs for the previous reporting period plus or minus any adjustments which are based on the lessee's knowledge of decreases or increases that will affect the allowance. MMS must receive the Form MMS-4110 within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).</P> <P>(iv) For new transportation facilities or arrangements, the lessee's initial Form MMS-4110 shall include estimates of the allowable oil transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.</P> <P>(v) Non-arm's-length contract or no-contract transportation allowances which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.</P> <P>(vi) Upon request by MMS, the lessee shall submit all data used to prepare its Form MMS-4110. The data shall be provided within a reasonable period of time, as determined by MMS.</P> <P>(vii) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.</P> <P>(viii) If the lessee is authorized to use its FERC-approved tariff as its transportation cost in accordance with paragraph (b)(5) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.</P> <P>(3) MMS may establish reporting dates for individual lessees different from those specified in this subpart in order to provide more effective administration. Lessees will be notified of any change in their reporting period.<PRTPAGE P="63"/> </P> <P>(4) Transportation allowances must be reported as a separate line item on Form MMS-2014, unless MMS approves a different reporting procedure.</P> <P>(d) <E T="03">Interest assessments for incorrect or late reports and for failure to report.</E> (1) If a lessee deducts a transportation allowance on its Form MMS-2014 without complying with the requirements of this section, the lessee shall pay interest only on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section.</P> <P>(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.</P> <P>(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.</P> <P>(e) <E T="03">Adjustments.</E> (1) If the actual transportation allowance is less than the amount the lessee has taken on Form MMS-2014 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest computed under 30 CFR 218.54, retroactive to the first day of the first month the lessee is authorized to deduct a transportation allowance. If the actual transportation allowance is greater than the amount the lessee has taken on Form MMS-2014 for each month during the allowance form reporting period, the lessee shall be entitled to a credit without interest.</P> <P>(2) For lessees transporting production from Indian leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.</P> <P>(f) <E T="03">Actual or theoretical losses.</E> Notwithstanding any other provisions of this subpart, for other than arm's-length contracts, no cost shall be allowed for oil transportation which results from payments (either volumetric or for value) for actual or theoretical losses. This section does not apply when the transportation allowance is based upon a FERC or State regulatory agency approved tariff.</P> <P>(g) <E T="03">Other transportation cost determinations.</E> The provisions of this section shall apply to determine transportation costs when establishing value using a netback valuation procedure or any other procedure that requires deduction of transportation costs.</P> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Federal Oil</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>65 FR 14088, Mar. 15, 2000, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 206.100</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <P>(a) This subpart applies to all oil produced from Federal oil and gas leases onshore and on the Outer Continental Shelf (OCS). It explains how you as a lessee must calculate the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms.</P> <P>(b) If you are a designee and if you dispose of production on behalf of a lessee, the terms “you” and “your” in this subpart refer to you and not to the lessee. In this circumstance, you must determine and report royalty value for the lessee's oil by applying the rules in this subpart to your disposition of the lessee's oil.</P> <P>(c) If you are a designee and only report for a lessee, and do not dispose of the lessee's production, references to “you” and “your” in this subpart refer to the lessee and not the designee. In this circumstance, you as a designee must determine and report royalty value for the lessee's oil by applying the rules in this subpart to the lessee's disposition of its oil.</P> <P>(d) If the regulations in this subpart are inconsistent with:</P> <P>(1) A Federal statute;</P> <P>(2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation;</P> <P>(3) A written agreement between the lessee and the MMS Director establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under this subpart; or</P> <P>(4) An express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, <PRTPAGE P="64"/>written agreement, or lease provision will govern to the extent of the inconsistency.</P> <P>(e) MMS may audit and adjust all royalty payments.</P> </SECTION> <SECTION> <SECTNO>§ 206.101</SECTNO> <SUBJECT>What definitions apply to this subpart?</SUBJECT> <P>The following definitions apply to this subpart:</P> <P> <E T="03">Affiliate</E> means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:</P> <P>(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.</P> <P>(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:</P> <P>(i) The extent to which there are common officers or directors;</P> <P>(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;</P> <P>(iii) Operation of a lease, plant, or other facility;</P> <P>(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, or other facility; and</P> <P>(v) Other evidence of power to exercise control over or common control with another person.</P> <P>(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.</P> <P> <E T="03">ANS</E> means Alaska North Slope (ANS).</P> <P> <E T="03">Area</E> means a geographic region at least as large as the limits of an oil field, in which oil has similar quality, economic, and legal characteristics.</P> <P> <E T="03">Arm's-length contract</E> means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.</P> <P> <E T="03">Audit</E> means a review, conducted under generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees, designees or other persons who pay royalties, rents, or bonuses on Federal leases.</P> <P> <E T="03">BLM</E> means the Bureau of Land Management of the Department of the Interior.</P> <P> <E T="03">Condensate</E> means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without processing. Condensate is the mixture of liquid hydrocarbons resulting from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.</P> <P> <E T="03">Contract</E> means any oral or written agreement, including amendments or revisions, between two or more persons, that is enforceable by law and that with due consideration creates an obligation.</P> <P> <E T="03">Designee</E> means the person the lessee designates to report and pay the lessee's royalties for a lease.</P> <P> <E T="03">Exchange agreement</E> means an agreement where one person agrees to deliver oil to another person at a specified location in exchange for oil deliveries at another location. Exchange agreements may or may not specify prices for the oil involved. They frequently specify dollar amounts reflecting location, quality, or other differentials. Exchange agreements include buy/sell agreements, which specify prices to be paid at each exchange point and may appear to be two separate sales within the same agreement. Examples of other types of exchange agreements include, but are not limited to, exchanges of produced oil for specific types of crude oil (e.g., West <PRTPAGE P="65"/>Texas Intermediate); exchanges of produced oil for other crude oil at other locations (Location Trades); exchanges of produced oil for other grades of oil (Grade Trades); and multi-party exchanges.</P> <P> <E T="03">Field</E> means a geographic region situated over one or more subsurface oil and gas reservoirs and encompassing at least the outermost boundaries of all oil and gas accumulations known within those reservoirs, vertically projected to the land surface. State oil and gas regulatory agencies usually name onshore fields and designate their official boundaries. MMS names and designates boundaries of OCS fields.</P> <P> <E T="03">Gathering</E> means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area, or to a central accumulation or treatment point off the lease, unit, or communitized area that BLM or MMS approves for onshore and offshore leases, respectively.</P> <P> <E T="03">Gross proceeds</E> means the total monies and other consideration accruing for the disposition of oil produced. Gross proceeds also include, but are not limited to, the following examples:</P> <P>(1) Payments for services such as dehydration, marketing, measurement, or gathering which the lessee must perform at no cost to the Federal Government;</P> <P>(2) The value of services, such as salt water disposal, that the producer normally performs but that the buyer performs on the producer's behalf;</P> <P>(3) Reimbursements for harboring or terminaling fees;</P> <P>(4) Tax reimbursements, even though the Federal royalty interest may be exempt from taxation;</P> <P>(5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods, by allocating such payments over the production whose price the payment reduces and including the allocated amounts as proceeds for the production as it occurs; and</P> <P>(6) Monies and all other consideration to which a seller is contractually or legally entitled, but does not seek to collect through reasonable efforts.</P> <P> <E T="03">Lease</E> means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of oil or gas—or the land area covered by that authorization, whichever the context requires.</P> <P> <E T="03">Lessee</E> means any person to whom the United States issues an oil and gas lease, an assignee of all or a part of the record title interest, or any person to whom operating rights in a lease have been assigned.</P> <P> <E T="03">Location differential</E> means an amount paid or received (whether in money or in barrels of oil) under an exchange agreement that results from differences in location between oil delivered in exchange and oil received in the exchange. A location differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement.</P> <P> <E T="03">Market center</E> means a major point MMS recognizes for oil sales, refining, or transshipment. Market centers generally are locations where MMS-approved publications publish oil spot prices.</P> <P> <E T="03">Marketable condition</E> means oil sufficiently free from impurities and otherwise in a condition a purchaser will accept under a sales contract typical for the field or area.</P> <P> <E T="03">MMS-approved publication</E> means a publication MMS approves for determining ANS spot prices or WTI differentials.</P> <P> <E T="03">Netting</E> means reducing the reported sales value to account for transportation instead of reporting a transportation allowance as a separate entry on Form MMS-2014.</P> <P> <E T="03">NYMEX price</E> means the average of the New York Mercantile Exchange (NYMEX) settlement prices for light sweet crude oil delivered at Cushing, Oklahoma, calculated as follows:</P> <P>(1) Sum the prices published for each day during the calendar month of production (excluding weekends and holidays) for oil to be delivered in the prompt month corresponding to each such day; and</P> <P>(2) Divide the sum by the number of days on which those prices are published (excluding weekends and holidays).<PRTPAGE P="66"/> </P> <P> <E T="03">Oil</E> means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs, remains liquid at atmospheric pressure after passing through surface separating facilities, and is marketed or used as a liquid. Condensate recovered in lease separators or field facilities is oil.</P> <P> <E T="03">Outer Continental Shelf (OCS)</E> means all submerged lands lying 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 of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.</P> <P> <E T="03">Person</E> means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).</P> <P> <E T="03">Prompt month</E> means the nearest month of delivery for which NYMEX futures prices are published during the trading month.</P> <P> <E T="03">Quality differential</E> means an amount paid or received under an exchange agreement (whether in money or in barrels of oil) that results from differences in API gravity, sulfur content, viscosity, metals content, and other quality factors between oil delivered and oil received in the exchange. A quality differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell agreement.</P> <P> <E T="03">Rocky Mountain Region</E> means the States of Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming, except for those portions of the San Juan Basin and other oil-producing fields in the “Four Corners” area that lie within Colorado and Utah.</P> <P> <E T="03">Roll</E> means an adjustment to the NYMEX price that is calculated as follows:</P> <P>Roll = .6667 × (P<E T="52">0</E>−P<E T="52">1</E>) + .3333 × (P<E T="52">0</E>−P<E T="52">2</E>), where: P<E T="52">0</E> = the average of the daily NYMEX settlement prices for deliveries during the prompt month that is the same as the month of production, as published for each day during the trading month for which the month of production is the prompt month; P<E T="52">1</E> = the average of the daily NYMEX settlement prices for deliveries during the month following the month of production, published for each day during the trading month for which the month of production is the prompt month; and P<E T="52">2</E> = the average of the daily NYMEX settlement prices for deliveries during the second month following the month of production, as published for each day during the trading month for which the month of production is the prompt month. Calculate the average of the daily NYMEX settlement prices using only the days on which such prices are published (excluding weekends and holidays).</P> <P>(1) <E T="03">Example 1. Prices in Out Months are Lower Going Forward:</E> The month of production for which you must determine royalty value is March. March was the prompt month (for year 2003) from January 22 through February 20. April was the first month following the month of production, and May was the second month following the month of production. P<E T="52">0</E> therefore is the average of the daily NYMEX settlement prices for deliveries during March published for each business day between January 22 and February 20. P<E T="52">1</E> is the average of the daily NYMEX settlement prices for deliveries during April published for each business day between January 22 and February 20. P<E T="52">2</E> is the average of the daily NYMEX settlement prices for deliveries during May published for each business day between January 22 and February 20. In this example, assume that P<E T="52">0</E> = $28.00 per bbl, P<E T="52">1</E> = $27.70 per bbl, and P<E T="52">2</E> = $27.10 per bbl. In this example (a declining market), Roll = .6667 × ($28.00−$27.70) + .3333 × ($28.00−$27.10) = $.20 + $.30 = $.50. You add this number to the NYMEX price.</P> <P>(2) <E T="03">Example 2. Prices in Out Months are Higher Going Forward:</E> The month of production for which you must determine royalty value is July. July 2003 was the prompt month from May 21 through June 20. August was the first month following the month of production, and September was the second month following the month of production. P<E T="52">0</E> therefore is the average of the daily NYMEX settlement prices for deliveries during July published for each business day between May 21 and June 20. P<E T="52">1</E> is the average of the daily NYMEX settlement prices for deliveries during August published for each business day between May 21 and June <PRTPAGE P="67"/>20. P<E T="52">2</E> is the average of the daily NYMEX settlement prices for deliveries during September published for each business day between May 21 and June 20. In this example, assume that P<E T="52">0</E> = $28.00 per bbl, P<E T="52">1</E> = $28.90 per bbl, and P<E T="52">2</E> = $29.50 per bbl. In this example (a rising market), Roll = .6667 × ($28.00−$28.90) + .3333 × ($28.00−$29.50) = (−$.60) + (−$.50) = −$1.10. You add this negative number to the NYMEX price (effectively a subtraction from the NYMEX price).</P> <P> <E T="03">Sale</E> means a contract between two persons where:</P> <P>(1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights such as the right to buy back similar quantities of oil from the buyer elsewhere;</P> <P>(2) The buyer pays money or other consideration for the oil; and</P> <P>(3) The parties' intent is for a sale of the oil to occur.</P> <P> <E T="03">Spot price</E> means the price under a spot sales contract where:</P> <P>(1) A seller agrees to sell to a buyer a specified amount of oil at a specified price over a specified period of short duration;</P> <P>(2) No cancellation notice is required to terminate the sales agreement; and</P> <P>(3) There is no obligation or implied intent to continue to sell in subsequent periods.</P> <P> <E T="03">Tendering program</E> means a producer's offer of a portion of its crude oil produced from a field or area for competitive bidding, regardless of whether the production is offered or sold at or near the lease or unit or away from the lease or unit.</P> <P> <E T="03">Trading month</E> means the period extending from the second business day before the 25th day of the second calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the second business day before the last business day preceding the 25th day of that month) through the third business day before the 25th day of the calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the third business day before the last business day preceding the 25th day of that month), unless the NYMEX publishes a different definition or different dates on its official Web site, <E T="03">www.nymex.com,</E> in which case the NYMEX definition will apply.</P> <P> <E T="03">Transportation allowance</E> means a deduction in determining royalty value for the reasonable, actual costs of moving oil to a point of sale or delivery off the lease, unit area, or communitized area. The transportation allowance does not include gathering costs.</P> <P> <E T="03">WTI differential</E> means the average of the daily mean differentials for location and quality between a grade of crude oil at a market center and West Texas Intermediate (WTI) crude oil at Cushing published for each day for which price publications perform surveys for deliveries during the production month, calculated over the number of days on which those differentials are published (excluding weekends and holidays). Calculate the daily mean differentials by averaging the daily high and low differentials for the month in the selected publication. Use only the days and corresponding differentials for which such differentials are published.</P> <P>(1) <E T="03">Example.</E> Assume the production month was March 2003. Industry trade publications performed their price surveys and determined differentials during January 26 through February 25 for oil delivered in March. The WTI differential (for example, the West Texas Sour crude at Midland, Texas, spread versus WTI) applicable to valuing oil produced in the March 2003 production month would be determined using all the business days for which differentials were published during the period January 26 through February 25 excluding weekends and holidays (22 days). To calculate the WTI differential, add together all of the daily mean differentials published for January 26 through February 25 and divide that sum by 22.</P> <P>(2) [Reserved]</P> <CITA>[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24975, May 5, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.102</SECTNO> <SUBJECT>How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm's-length contract?</SUBJECT> <P>(a) The value of oil under this section is the gross proceeds accruing to the seller under the arm's-length contract, less applicable allowances determined under §§ 206.110 or 206.111. This value <PRTPAGE P="68"/>does not apply if you exercise an option to use a different value provided in paragraph (d)(1) or (d)(2)(i) of this section, or if one of the exceptions in paragraph (c) of this section applies. Use this paragraph (a) to value oil that:</P> <P>(1) You sell under an arm's-length sales contract; or</P> <P>(2) You sell or transfer to your affiliate or another person under a non-arm's-length contract and that affiliate or person, or another affiliate of either of them, then sells the oil under an arm's-length contract, unless you exercise the option provided in paragraph (d)(2)(i) of this section.</P> <P>(b) If you have multiple arm's-length contracts to sell oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the volume-weighted average of the values established under this section for each contract for the sale of oil produced from that lease.</P> <P>(c) This paragraph contains exceptions to the valuation rule in paragraph (a) of this section. Apply these exceptions on an individual contract basis.</P> <P>(1) In conducting reviews and audits, if MMS determines that any arm's-length sales contract does not reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller, MMS may require that you value the oil sold under that contract either under § 206.103 or at the total consideration received.</P> <P>(2) You must value the oil under § 206.103 if MMS determines that the value under paragraph (a) of this section does not reflect the reasonable value of the production due to either:</P> <P>(i) Misconduct by or between the parties to the arm's-length contract; or</P> <P>(ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.</P> <P>(A) MMS will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm's-length sales contract.</P> <P>(B) The fact that the price received by the seller under an arm's length contract is less than other measures of market price, such as index prices, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil from the lease.</P> <P>(d)(1) If you enter into an arm's-length exchange agreement, or multiple sequential arm's-length exchange agreements, and following the exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm's-length contract, then you may use either § 206.102(a) or § 206.103 to value your production for royalty purposes.</P> <P>(i) If you use § 206.102(a), your gross proceeds are the gross proceeds under your or your affiliate's arm's-length sales contract after the exchange(s) occur(s). You must adjust your gross proceeds for any location or quality differential, or other adjustments, you received or paid under the arm's-length exchange agreement(s). If MMS determines that any arm's-length exchange agreement does not reflect reasonable location or quality differentials, MMS may require you to value the oil under § 206.103. You may not otherwise use the price or differential specified in an arm's-length exchange agreement to value your production.</P> <P>(ii) When you elect under § 206.102(d)(1) to use § 206.102(a) or § 206.103, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) sold under arm's-length contracts following arm's-length exchange agreements. You may not change your election more often than once every 2 years.</P> <P>(2)(i) If you sell or transfer your oil production to your affiliate and that affiliate or another affiliate then sells the oil under an arm's-length contract, you may use either § 206.102(a) or § 206.103 to value your production for royalty purposes.</P> <P>(ii) When you elect under § 206.102(d)(2)(i) to use § 206.102(a) or § 206.103, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) that your affiliates resell at <PRTPAGE P="69"/>arm's length. You may not change your election more often than once every 2 years.</P> <P>(e) If you value oil under paragraph (a) of this section:</P> <P>(1) MMS may require you to certify that your or your affiliate's arm's-length contract provisions include all of the consideration the buyer must pay, either directly or indirectly, for the oil.</P> <P>(2) You must base value on the highest price the seller can receive through legally enforceable claims under the contract.</P> <P>(i) If the seller fails to take proper or timely action to receive prices or benefits it is entitled to, you must pay royalty at a value based upon that obtainable price or benefit. But you will owe no additional royalties unless or until the seller receives monies or consideration resulting from the price increase or additional benefits, if:</P> <P>(A) The seller makes timely application for a price increase or benefit allowed under the contract;</P> <P>(B) The purchaser refuses to comply; and</P> <P>(C) The seller takes reasonable documented measures to force purchaser compliance.</P> <P>(ii) Paragraph (e)(2)(i) of this section will not permit you to avoid your royalty payment obligation where a purchaser fails to pay, pays only in part, or pays late. Any contract revisions or amendments that reduce prices or benefits to which the seller is entitled must be in writing and signed by all parties to the arm's-length contract.</P> </SECTION> <SECTION> <SECTNO>§ 206.103</SECTNO> <SUBJECT>How do I value oil that is not sold under an arm's-length contract?</SUBJECT> <P>This section explains how to value oil that you may not value under § 206.102 or that you elect under § 206.102(d) to value under this section. First determine whether paragraph (a), (b), or (c) of this section applies to production from your lease, or whether you may apply paragraph (d) or (e) with MMS approval.</P> <P>(a) <E T="03">Production from leases in California or Alaska.</E> Value is the average of the daily mean ANS spot prices published in any MMS-approved publication during the trading month most concurrent with the production month. (For example, if the production month is June, compute the average of the daily mean prices using the daily ANS spot prices published in the MMS-approved publication for all the business days in June.)</P> <P>(1) To calculate the daily mean spot price, average the daily high and low prices for the month in the selected publication.</P> <P>(2) Use only the days and corresponding spot prices for which such prices are published.</P> <P>(3) You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under § 206.112.</P> <P>(4) After you select an MMS-approved publication, you may not select a different publication more often than once every 2 years, unless the publication you use is no longer published or MMS revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period.</P> <P>(b) <E T="03">Production from leases in the Rocky Mountain Region.</E> This paragraph provides methods and options for valuing your production under different factual situations. You must consistently apply paragraph (b)(1), (b)(2), or (b)(3) of this section to value all of your production from the same unit, communitization agreement, or lease (if the lease or a portion of the lease is not part of a unit or communitization agreement) that you cannot value under § 206.102 or that you elect under § 206.102(d) to value under this section.</P> <P>(1) If you have an MMS-approved tendering program, you must value oil produced from leases in the area the tendering program covers at the highest winning bid price for tendered volumes.</P> <P>(i) The minimum requirements for MMS to approve your tendering program are:</P> <P>(A) You must offer and sell at least 30 percent of your or your affiliates' production from both Federal and non-Federal leases in the area under your tendering program; and<PRTPAGE P="70"/> </P> <P>(B) You must receive at least three bids for the tendered volumes from bidders who do not have their own tendering programs that cover some or all of the same area.</P> <P>(ii) If you do not have an MMS-approved tendering program, you may elect to value your oil under either paragraph (b)(2) or (b)(3) of this section. After you select either paragraph (b)(2) or (b)(3) of this section, you may not change to the other method more often than once every 2 years, unless the method you have been using is no longer applicable and you must apply the other paragraph. If you change methods, you must begin a new 2-year period.</P> <P>(2) Value is the volume-weighted average of the gross proceeds accruing to the seller under your or your affiliates' arm's-length contracts for the purchase or sale of production from the field or area during the production month.</P> <P>(i) The total volume purchased or sold under those contracts must exceed 50 percent of your and your affiliates' production from both Federal and non-Federal leases in the same field or area during that month.</P> <P>(ii) Before calculating the volume-weighted average, you must normalize the quality of the oil in your or your affiliates' arm's-length purchases or sales to the same gravity as that of the oil produced from the lease.</P> <P>(3) Value is the NYMEX price (without the roll), adjusted for applicable location and quality differentials and transportation costs under § 206.112.</P> <P>(4) If you demonstrate to MMS's satisfaction that paragraphs (b)(1) through (b)(3) of this section result in an unreasonable value for your production as a result of circumstances regarding that production, the MMS Director may establish an alternative valuation method.</P> <P>(c) <E T="03">Production from leases not located in California, Alaska, or the Rocky Mountain Region.</E> (1) Value is the NYMEX price, plus the roll, adjusted for applicable location and quality differentials and transportation costs under § 206.112.</P> <P>(2) If the MMS Director determines that use of the roll no longer reflects prevailing industry practice in crude oil sales contracts or that the most common formula used by industry to calculate the roll changes, MMS may terminate or modify use of the roll under paragraph (c)(1) of this section at the end of each 2-year period following July 6, 2004, through notice published in the <E T="04">Federal Register</E> not later than 60 days before the end of the 2-year period. MMS will explain the rationale for terminating or modifying the use of the roll in this notice.</P> <P>(d) <E T="03">Unreasonable value.</E> If MMS determines that the NYMEX price or ANS spot price does not represent a reasonable royalty value in any particular case, MMS may establish reasonable royalty value based on other relevant matters.</P> <P>(e) <E T="03">Production delivered to your refinery and the NYMEX price or ANS spot price is an unreasonable value.</E> (1) Instead of valuing your production under paragraph (a), (b), or (c) of this section, you may apply to the MMS Director to establish a value representing the market at the refinery if:</P> <P>(i) You transport your oil directly to your or your affiliate's refinery, or exchange your oil for oil delivered to your or your affiliate's refinery; and</P> <P>(ii) You must value your oil under this section at the NYMEX price or ANS spot price; and</P> <P>(iii) You believe that use of the NYMEX price or ANS spot price results in an unreasonable royalty value.</P> <P>(2) You must provide adequate documentation and evidence demonstrating the market value at the refinery. That evidence may include, but is not limited to:</P> <P>(i) Costs of acquiring other crude oil at or for the refinery;</P> <P>(ii) How adjustments for quality, location, and transportation were factored into the price paid for other oil;</P> <P>(iii) Volumes acquired for and refined at the refinery; and</P> <P>(iv) Any other appropriate evidence or documentation that MMS requires.</P> <P>(3) If the MMS Director establishes a value representing market value at the refinery, you may not take an allowance against that value under <PRTPAGE P="71"/>§ 206.112(b) unless it is included in the Director's approval.</P> <CITA>[65 FR 14088, Mar. 15, 2002, as amended at 67 FR 19111, Apr. 18, 2002; 69 FR 24976, May 5, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.104</SECTNO> <SUBJECT>What publications are acceptable to MMS?</SUBJECT> <P>(a) MMS periodically will publish in the <E T="04">Federal Register</E> a list of acceptable publications for the NYMEX price and ANS spot price based on certain criteria, including, but not limited to:</P> <P>(1) Publications buyers and sellers frequently use;</P> <P>(2) Publications frequently mentioned in purchase or sales contracts;</P> <P>(3) Publications that use adequate survey techniques, including development of estimates based on daily surveys of buyers and sellers of crude oil, and, for ANS spot prices, buyers and sellers of ANS crude oil; and</P> <P>(4) Publications independent from MMS, other lessors, and lessees.</P> <P>(b) Any publication may petition MMS to be added to the list of acceptable publications.</P> <P>(c) MMS will specify the tables you must use in the acceptable publications.</P> <P>(d) MMS may revoke its approval of a particular publication if it determines that the prices or differentials published in the publication do not accurately represent NYMEX prices or differentials or ANS spot market prices or differentials.</P> <CITA>[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.105</SECTNO> <SUBJECT>What records must I keep to support my calculations of value under this subpart?</SUBJECT> <P>If you determine the value of your oil under this subpart, you must retain all data relevant to the determination of royalty value.</P> <P>(a) You must be able to show:</P> <P>(1) How you calculated the value you reported, including all adjustments for location, quality, and transportation, and</P> <P>(2) How you complied with these rules.</P> <P>(b) Recordkeeping requirements are found at part 207 of this chapter.</P> <P>(c) MMS may review and audit your data, and MMS will direct you to use a different value if it determines that the reported value is inconsistent with the requirements of this subpart.</P> </SECTION> <SECTION> <SECTNO>§ 206.106</SECTNO> <SUBJECT>What are my responsibilities to place production into marketable condition and to market production?</SUBJECT> <P>You must place oil in marketable condition and market the oil for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. If you use gross proceeds under an arm's-length contract in determining value, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the oil in marketable condition or to market the oil.</P> </SECTION> <SECTION> <SECTNO>§ 206.107</SECTNO> <SUBJECT>How do I request a value determination?</SUBJECT> <P>(a) You may request a value determination from MMS regarding any Federal lease oil production. Your request must:</P> <P>(1) Be in writing;</P> <P>(2) Identify specifically all leases involved, the record title or operating rights owners of those leases, and the designees for those leases;</P> <P>(3) Completely explain all relevant facts. You must inform MMS of any changes to relevant facts that occur before we respond to your request;</P> <P>(4) Include copies of all relevant documents;</P> <P>(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and</P> <P>(6) Suggest your proposed valuation method.</P> <P>(b) MMS will reply to requests expeditiously. MMS may either:</P> <P>(1) Issue a value determination signed by the Assistant Secretary, Land and Minerals Management; or</P> <P>(2) Issue a value determination by MMS; or</P> <P>(3) Inform you in writing that MMS will not provide a value determination. Situations in which MMS typically will not provide any value determination include, but are not limited to:</P> <P>(i) Requests for guidance on hypothetical situations; and<PRTPAGE P="72"/> </P> <P>(ii) Matters that are the subject of pending litigation or administrative appeals.</P> <P>(c)(1) A value determination signed by the Assistant Secretary, Land and Minerals Management, is binding on both you and MMS until the Assistant Secretary modifies or rescinds it.</P> <P>(2) After the Assistant Secretary issues a value determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay late payment interest under 30 CFR 218.54.</P> <P>(3) A value determination signed by the Assistant Secretary is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706.</P> <P>(d) A value determination issued by MMS is binding on MMS and delegated States with respect to the specific situation addressed in the determination unless the MMS (for MMS-issued value determinations) or the Assistant Secretary modifies or rescinds it.</P> <P>(1) A value determination by MMS is not an appealable decision or order under 30 CFR part 290 subpart B.</P> <P>(2) If you receive an order requiring you to pay royalty on the same basis as the value determination, you may appeal that order under 30 CFR part 290 subpart B.</P> <P>(e) In making a value determination, MMS or the Assistant Secretary may use any of the applicable valuation criteria in this subpart.</P> <P>(f) A change in an applicable statute or regulation on which any value determination is based takes precedence over the value determination, regardless of whether the MMS or the Assistant Secretary modifies or rescinds the value determination.</P> <P>(g) The MMS or the Assistant Secretary generally will not retroactively modify or rescind a value determination issued under paragraph (d) of this section, unless:</P> <P>(1) There was a misstatement or omission of material facts; or</P> <P>(2) The facts subsequently developed are materially different from the facts on which the guidance was based.</P> <P>(h) MMS may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 206.108.</P> </SECTION> <SECTION> <SECTNO>§ 206.108</SECTNO> <SUBJECT>Does MMS protect information I provide?</SUBJECT> <P>Certain information you submit to MMS regarding valuation of oil, including transportation allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, MMS will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.</P> </SECTION> <SECTION> <SECTNO>§ 206.109</SECTNO> <SUBJECT>When may I take a transportation allowance in determining value?</SUBJECT> <P>(a) <E T="03">Transportation allowances permitted when value is based on gross proceeds.</E> MMS will allow a deduction for the reasonable, actual costs to transport oil from the lease to the point off the lease under §§ 206.110 or 206.111, as applicable. This paragraph applies when:</P> <P>(1) You value oil under § 206.102 based on gross proceeds from a sale at a point off the lease, unit, or communitized area where the oil is produced, and</P> <P>(2) The movement to the sales point is not gathering.</P> <P>(b) <E T="03">Transportation allowances and other adjustments that apply when value is based on NYMEX prices or ANS spot prices.</E> If you value oil using NYMEX prices or ANS spot prices under § 206.103, MMS will allow an adjustment for certain location and quality differentials and certain costs associated with transporting oil as provided under § 206.112.</P> <P>(c) <E T="03">Limits on transportation allowances.</E> (1) Except as provided in paragraph (c)(2) of this section, your transportation allowance may not exceed 50 percent of the value of the oil as determined under § 206.102 or § 206.103 of this subpart. You may not use transportation costs incurred to move a particular volume of production to reduce royalties owed on production for which those costs were not incurred.</P> <P>(2) You may ask MMS to approve a transportation allowance in excess of the limitation in paragraph (c)(1) of <PRTPAGE P="73"/>this section. You must demonstrate that the transportation costs incurred were reasonable, actual, and necessary. Your application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination. You may never reduce the royalty value of any production to zero.</P> <P>(d) <E T="03">Allocation of transportation costs.</E> You must allocate transportation costs among all products produced and transported as provided in §§ 206.110 and 206.111. You must express transportation allowances for oil as dollars per barrel.</P> <P>(e) <E T="03">Liability for additional payments.</E> If MMS determines that you took an excessive transportation allowance, then you must pay any additional royalties due, plus interest under 30 CFR 218.54. You also could be entitled to a credit with interest under applicable rules if you understated your transportation allowance. If you take a deduction for transportation on Form MMS-2014 by improperly netting the allowance against the sales value of the oil instead of reporting the allowance as a separate entry, MMS may assess you an amount under § 206.116.</P> <CITA>[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.110</SECTNO> <SUBJECT>How do I determine a transportation allowance under an arm's-length transportation contract?</SUBJECT> <P>(a) If you or your affiliate incur transportation costs under an arm's-length transportation contract, you may claim a transportation allowance for the reasonable, actual costs incurred as more fully explained in paragraph (b) of this section, except as provided in paragraphs (a)(1) and (a)(2) of this section and subject to the limitation in § 206.109(c). You must be able to demonstrate that your or your affiliate's contract is at arm's length. You do not need MMS approval before reporting a transportation allowance for costs incurred under an arm's-length transportation contract.</P> <P>(1) If MMS determines that the contract reflects more than the consideration actually transferred either directly or indirectly from you or your affiliate to the transporter for the transportation, MMS may require that you calculate the transportation allowance under § 206.111.</P> <P>(2) You must calculate the transportation allowance under § 206.111 if MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the reasonable value of the transportation due to either:</P> <P>(i) Misconduct by or between the parties to the arm's-length contract; or</P> <P>(ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor.</P> <P>(A) MMS will not use this provision to simply substitute its judgment of the reasonable oil transportation costs incurred by you or your affiliate under an arm's-length transportation contract.</P> <P>(B) The fact that the cost you or your affiliate incur in an arm's length transaction is higher than other measures of transportation costs, such as rates paid by others in the field or area, is insufficient to establish breach of the duty to market unless MMS finds additional evidence that you or your affiliate acted unreasonably or in bad faith in transporting oil from the lease.</P> <P>(b) You may deduct any of the following actual costs you (including your affiliates) incur for transporting oil. You may not use as a deduction any cost that duplicates all or part of any other cost that you use under this paragraph.</P> <P>(1) The amount that you pay under your arm's-length transportation contract or tariff.</P> <P>(2) Fees paid (either in volume or in value) for actual or theoretical line losses.</P> <P>(3) Fees paid for administration of a quality bank.</P> <P>(4) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows:</P> <P>(i) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the pipeline by the value of that volume for the <PRTPAGE P="74"/>current month calculated under § 206.102 or § 206.103, as applicable; and</P> <P>(ii) Multiply the value calculated under paragraph (b)(4)(i) of this section by the monthly rate of return, calculated by dividing the rate of return specified in § 206.111(i)(2) by 12.</P> <P>(5) Fees paid to a terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance.</P> <P>(6) Fees paid for short-term storage (30 days or less) incidental to transportation as required by a transporter.</P> <P>(7) Fees paid to pump oil to another carrier's system or vehicles as required under a tariff.</P> <P>(8) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when you do not sell the oil at the hub. These fees do not include title transfer fees.</P> <P>(9) Payments for a volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation.</P> <P>(10) Costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to maintain.</P> <P>(c) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to the following:</P> <P>(1) Fees paid for long-term storage (more than 30 days).</P> <P>(2) Administrative, handling, and accounting fees associated with terminalling.</P> <P>(3) Title and terminal transfer fees.</P> <P>(4) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title transfer fees.</P> <P>(5) Fees paid to brokers.</P> <P>(6) Fees paid to a scheduling service provider.</P> <P>(7) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production.</P> <P>(8) Gauging fees.</P> <P>(d) If your arm's-length transportation contract includes more than one liquid product, and the transportation costs attributable to each product cannot be determined from the contract, then you must allocate the total transportation costs to each of the liquid products transported.</P> <P>(1) Your allocation must use the same proportion as the ratio of the volume of each product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value).</P> <P>(2) You may not claim an allowance for the costs of transporting lease production that is not royalty-bearing.</P> <P>(3) You may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS will approve the method unless it is not consistent with the purposes of the regulations in this subpart.</P> <P>(e) If your arm's-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, then you must propose an allocation procedure to MMS.</P> <P>(1) You may use your proposed procedure to calculate a transportation allowance until MMS accepts or rejects your cost allocation. If MMS rejects your cost allocation, you must amend your Form MMS-2014 for the months that you used the rejected method and pay any additional royalty and interest due.</P> <P>(2) You must submit your initial proposal, including all available data, within 3 months after first claiming the allocated deductions on Form MMS-2014.</P> <P>(f) If your payments for transportation under an arm's-length contract are not on a dollar-per-unit basis, you must convert whatever consideration is paid to a dollar-value equivalent.</P> <P>(g) If your arm's-length sales contract includes a provision reducing the contract price by a transportation factor, do not separately report the transportation factor as a transportation allowance on Form MMS-2014.</P> <P>(1) You may use the transportation factor in determining your gross proceeds for the sale of the product.</P> <P>(2) You must obtain MMS approval before claiming a transportation factor <PRTPAGE P="75"/>in excess of 50 percent of the base price of the product.</P> <CITA>[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24976, May 5, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.111</SECTNO> <SUBJECT>How do I determine a transportation allowance if I do not have an arm's-length transportation contract or arm's-length tariff?</SUBJECT> <P>(a) This section applies if you or your affiliate do not have an arm's-length transportation contract, including situations where you or your affiliate provide your own transportation services. Calculate your transportation allowance based on your or your affiliate's reasonable, actual costs for transportation during the reporting period using the procedures prescribed in this section.</P> <P>(b) Your or your affiliate's actual costs include the following:</P> <P>(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;</P> <P>(2) Overhead under paragraph (f) of this section;</P> <P>(3) Depreciation under paragraphs (g) and (h) of this section;</P> <P>(4) A return on undepreciated capital investment under paragraph (i) of this section; and</P> <P>(5) Once the transportation system has been depreciated below ten percent of total capital investment, a return on ten percent of total capital investment under paragraph (j) of this section.</P> <P>(6) To the extent not included in costs identified in paragraphs (d) through (j) of this section, you may also deduct the following actual costs. You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this section:</P> <P>(i) Volumetric adjustments for actual (not theoretical) line losses.</P> <P>(ii) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you as a shipper to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows:</P> <P>(A) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the pipeline by the value of that volume for the current month calculated under § 206.102 or § 206.103, as applicable; and</P> <P>(B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of this section by the monthly rate of return, calculated by dividing the rate of return specified in § 206.111(i)(2) by 12.</P> <P>(iii) Fees paid to a non-affiliated terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance.</P> <P>(iv) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when you do not sell the oil at the hub. These fees do not include title transfer fees.</P> <P>(v) A volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation.</P> <P>(vi) Fees paid to a non-affiliated quality bank administrator for administration of a quality bank.</P> <P>(7) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to the following:</P> <P>(i) Fees paid for long-term storage (more than 30 days).</P> <P>(ii) Administrative, handling, and accounting fees associated with terminalling.</P> <P>(iii) Title and terminal transfer fees.</P> <P>(iv) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title transfer fees.</P> <P>(v) Fees paid to brokers.</P> <P>(vi) Fees paid to a scheduling service provider.</P> <P>(vii) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production.</P> <P>(viii) Theoretical line losses.</P> <P>(ix) Gauging fees.</P> <P>(c) Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.</P> <P>(d) Allowable operating expenses include:</P> <P>(i) Operations supervision and engineering;</P> <P>(ii) Operations labor;<PRTPAGE P="76"/> </P> <P>(iii) Fuel;</P> <P>(iv) Utilities;</P> <P>(v) Materials;</P> <P>(vi) Ad valorem property taxes;</P> <P>(vii) Rent;</P> <P>(viii) Supplies; and</P> <P>(ix) Any other directly allocable and attributable operating expense which you can document.</P> <P>(e) Allowable maintenance expenses include:</P> <P>(i) Maintenance of the transportation system;</P> <P>(ii) Maintenance of equipment;</P> <P>(iii) Maintenance labor; and</P> <P>(iv) Other directly allocable and attributable maintenance expenses which you can document.</P> <P>(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(g) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit-of-production method. After you make an election, you may not change methods without MMS approval. You may not depreciate equipment below a reasonable salvage value.</P> <P>(h) This paragraph describes the basis for your depreciation schedule.</P> <P>(1) If you or your affiliate own a transportation system on June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs for production after June 1, 2000, on your total capital investment in the system (including your original purchase price or construction cost and subsequent reinvestment).</P> <P>(2) If you or your affiliate purchased the transportation system at arm's length before June 1, 2000, you must incorporate depreciation on the schedule based on your purchase price (and subsequent reinvestment) into your transportation allowance calculations for production after June 1, 2000, beginning at the point on the depreciation schedule corresponding to that date. You must prorate your depreciation for calendar year 2000 by claiming part-year depreciation for the period from June 1, 2000 until December 31, 2000. You may not adjust your transportation costs for production before June 1, 2000, using the depreciation schedule based on your purchase price.</P> <P>(3) If you are the original owner of the transportation system on June 1, 2000, or if you purchased your transportation system before March 1, 1988, you must continue to use your existing depreciation schedule in calculating actual transportation costs for production in periods after June 1, 2000.</P> <P>(4) If you or your affiliate purchase a transportation system at arm's length from the original owner after June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs on your total capital investment in the system (including your original purchase price and subsequent reinvestment). You must prorate your depreciation for the year in which you or your affiliate purchased the system to reflect the portion of that year for which you or your affiliate own the system.</P> <P>(5) If you or your affiliate purchase a transportation system at arm's length after June 1, 2000, from anyone other than the original owner, you must assume the depreciation schedule of the person from whom you bought the system. Include in the depreciation schedule any subsequent reinvestment.</P> <P>(i)(1) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transportation allowance by the rate of return provided in paragraph (i)(2) of this section.</P> <P>(2) The rate of return is 1.3 times the industrial bond yield index for Standard & Poor's BBB bond rating. Use the monthly average rate published in “Standard & Poor's Bond Guide” for the first month of the reporting period for which the allowance applies. Calculate the rate at the beginning of each subsequent transportation allowance reporting period.</P> <P>(j)(1) After a transportation system has been depreciated at or below a value equal to ten percent of your total capital investment, you may continue to include in the allowance calculation <PRTPAGE P="77"/>a cost equal to ten percent of your total capital investment in the transportation system multiplied by a rate of return under paragraph (i)(2) of this section.</P> <P>(2) You may apply this paragraph to a transportation system that before June 1, 2000, was depreciated at or below a value equal to ten percent of your total capital investment.</P> <P>(k) Calculate the deduction for transportation costs based on your or your affiliate's cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, allocate costs consistently and equitably to each of the liquid products transported. Your allocation must use the same proportion as the ratio of the volume of each liquid product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value).</P> <P>(1) You may not take an allowance for transporting lease production that is not royalty-bearing.</P> <P>(2) You may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS will approve the method if it is consistent with the purposes of the regulations in this subpart.</P> <P>(l)(1) Where you transport both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to MMS.</P> <P>(2) You may use your proposed procedure to calculate a transportation allowance until MMS accepts or rejects your cost allocation. If MMS rejects your cost allocation, you must amend your Form MMS-2014 for the months that you used the rejected method and pay any additional royalty and interest due.</P> <P>(3) You must submit your initial proposal, including all available data, within 3 months after first claiming the allocated deductions on Form MMS-2014.</P> <CITA>[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24977, May 5, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.112</SECTNO> <SUBJECT>What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices?</SUBJECT> <P>This section applies when you use NYMEX prices or ANS spot prices to calculate the value of production under § 206.103. As specified in this section, adjust the NYMEX price to reflect the difference in value between your lease and Cushing, Oklahoma, or adjust the ANS spot price to reflect the difference in value between your lease and the appropriate MMS-recognized market center at which the ANS spot price is published (for example, Long Beach, California, or San Francisco, California). Paragraph (a) of this section explains how you adjust the value between the lease and the market center, and paragraph (b) of this section explains how you adjust the value between the market center and Cushing when you use NYMEX prices. Paragraph (c) of this section explains how adjustments may be made for quality differentials that are not accounted for through exchange agreements. Paragraph (d) of this section gives some examples. References in this section to “you” include your affiliates as applicable.</P> <P>(a) To adjust the value between the lease and the market center:</P> <P>(1)(i) For oil that you exchange at arm's length between your lease and the market center (or between any intermediate points between those locations), you must calculate a lease-to-market center differential by the applicable location and quality differentials derived from your arm's-length exchange agreement applicable to production during the production month.</P> <P>(ii) For oil that you exchange between your lease and the market center (or between any intermediate points between those locations) under an exchange agreement that is not at arm's length, you must obtain approval from MMS for a location and quality differential. Until you obtain such approval, you may use the location and quality differential derived from that exchange agreement applicable to production during the production month. If MMS prescribes a different differential, you must apply MMS's differential to all periods for which you used <PRTPAGE P="78"/>your proposed differential. You must pay any additional royalties owed resulting from using MMS's differential plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).</P> <P>(2) For oil that you transport between your lease and the market center (or between any intermediate points between those locations), you may take an allowance for the cost of transporting that oil between the relevant points as determined under § 206.110 or § 206.111, as applicable.</P> <P>(3) If you transport or exchange at arm's length (or both transport and exchange) at least 20 percent, but not all, of your oil produced from the lease to a market center, determine the adjustment between the lease and the market center for the oil that is not transported or exchanged (or both transported and exchanged) to or through a market center as follows:</P> <P>(i) Determine the volume-weighted average of the lease-to-market center adjustment calculated under paragraphs (a)(1) and (a)(2) of this section for the oil that you do transport or exchange (or both transport and exchange) from your lease to a market center.</P> <P>(ii) Use that volume-weighted average lease-to-market center adjustment as the adjustment for the oil that you do not transport or exchange (or both transport and exchange) from your lease to a market center.</P> <P>(4) If you transport or exchange (or both transport and exchange) less than 20 percent of the crude oil produced from your lease between the lease and a market center, you must propose to MMS an adjustment between the lease and the market center for the portion of the oil that you do not transport or exchange (or both transport and exchange) to a market center. Until you obtain such approval, you may use your proposed adjustment. If MMS prescribes a different adjustment, you must apply MMS's adjustment to all periods for which you used your proposed adjustment. You must pay any additional royalties owed resulting from using MMS's adjustment plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).</P> <P>(5) You may not both take a transportation allowance and use a location and quality adjustment or exchange differential for the same oil between the same points.</P> <P>(b) For oil that you value using NYMEX prices, adjust the value between the market center and Cushing, Oklahoma, as follows:</P> <P>(1) If you have arm's-length exchange agreements between the market center and Cushing under which you exchange to Cushing at least 20 percent of all the oil you own at the market center during the production month, you must use the volume-weighted average of the location and quality differentials from those agreements as the adjustment between the market center and Cushing for all the oil that you produce from the leases during that production month for which that market center is used.</P> <P>(2) If paragraph (b)(1) of this section does not apply, you must use the WTI differential published in an MMS-approved publication for the market center nearest your lease, for crude oil most similar in quality to your production, as the adjustment between the market center and Cushing. (For example, for light sweet crude oil produced offshore of Louisiana, use the WTI differential for Light Louisiana Sweet crude oil at St. James, Louisiana.) After you select an MMS-approved publication, you may not select a different publication more often than once every 2 years, unless the publication you use is no longer published or MMS revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period.</P> <P>(3) If neither paragraph (b)(1) nor (b)(2) of this section applies, you may propose an alternative differential to MMS. Until you obtain such approval, you may use your proposed differential. If MMS prescribes a different differential, you must apply MMS's differential to all periods for which you used your proposed differential. You must pay any additional royalties owed resulting from using MMS's differential plus late payment interest from the original royalty due date, or you <PRTPAGE P="79"/>may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h).</P> <P>(c)(1) If you adjust for location and quality differentials or for transportation costs under paragraphs (a) and (b) of this section, also adjust the NYMEX price or ANS spot price for quality based on premiums or penalties determined by pipeline quality bank specifications at intermediate commingling points or at the market center if those points are downstream of the royalty measurement point approved by MMS or BLM, as applicable. Make this adjustment only if and to the extent that such adjustments were not already included in the location and quality differentials determined from your arm's-length exchange agreements.</P> <P>(2) If the quality of your oil as adjusted is still different from the quality of the representative crude oil at the market center after making the quality adjustments described in paragraphs (a), (b) and (c)(1) of this section, you may make further gravity adjustments using posted price gravity tables. If quality bank adjustments do not incorporate or provide for adjustments for sulfur content, you may make sulfur adjustments, based on the quality of the representative crude oil at the market center, of 5.0 cents per one-tenth percent difference in sulfur content, unless MMS approves a higher adjustment.</P> <P>(d) The examples in this paragraph illustrate how to apply the requirement of this section.</P> <P>(1) <E T="03">Example.</E> Assume that a Federal lessee produces crude oil from a lease near Artesia, New Mexico. Further, assume that the lessee transports the oil to Roswell, New Mexico, and then exchanges the oil to Midland, Texas. Assume the lessee refines the oil received in exchange at Midland. Assume that the NYMEX price is $30.00/bbl, adjusted for the roll; that the WTI differential (Cushing to Midland) is −$.10/bbl; that the lessee's exchange agreement between Roswell and Midland results in a location and quality differential of −$.08/bbl; and that the lessee's actual cost of transporting the oil from Artesia to Roswell is $.40/bbl. In this example, the royalty value of the oil is $30.00−$.10−$.08—$.40 = $29.42/bbl.</P> <P>(2) <E T="03">Example.</E> Assume the same facts as in the example in paragraph (1), except that the lessee transports and exchanges to Midland 40 percent of the production from the lease near Artesia, and transports the remaining 60 percent directly to its own refinery in Ohio. In this example, the 40 percent of the production would be valued at $29.42/bbl, as explained in the previous example. In this example, the other 60 percent also would be valued at $29.42/bbl.</P> <P>(3) <E T="03">Example.</E> Assume that a Federal lessee produces crude oil from a lease near Bakersfield, California. Further, assume that the lessee transports the oil to Hynes Station, and then exchanges the oil to Cushing which it further exchanges with oil it refines. Assume that the ANS spot price is $20.00/bbl, and that the lessee's actual cost of transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The lessee must request approval from MMS for a location and quality adjustment between Hynes Station and Long Beach. For example, the lessee likely would propose using the tariff on Line 63 from Hynes Station to Long Beach as the adjustment between those points. Assume that adjustment to be $.72, including the sulfur and gravity bank adjustments, and that MMS approves the lessee's request. In this example, the preliminary (because the location and quality adjustment is subject to MMS review) royalty value of the oil is $20.00−$.72−$.28 = $19.00/bbl. The fact that oil was exchanged to Cushing does not change use of ANS spot prices for royalty valuation.</P> <CITA>[69 FR 24978, May 5, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.113</SECTNO> <SUBJECT>How will MMS identify market centers?</SUBJECT> <P>MMS periodically will publish in the <E T="04">Federal Register</E> a list of market centers. MMS will monitor market activity and, if necessary, add to or modify the list of market centers and will publish such modifications in the <E T="04">Federal Register.</E> MMS will consider the following factors and conditions in specifying market centers:<PRTPAGE P="80"/> </P> <P>(a) Points where MMS-approved publications publish prices useful for index purposes;</P> <P>(b) Markets served;</P> <P>(c) Input from industry and others knowledgeable in crude oil marketing and transportation;</P> <P>(d) Simplification; and</P> <P>(e) Other relevant matters.</P> </SECTION> <SECTION> <SECTNO>§ 206.114</SECTNO> <SUBJECT>What are my reporting requirements under an arm's-length transportation contract?</SUBJECT> <P>You or your affiliate must use a separate entry on Form MMS-2014 to notify MMS of an allowance based on transportation costs you or your affiliate incur. MMS may require you or your affiliate to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 207 of this chapter.</P> </SECTION> <SECTION> <SECTNO>§ 206.115</SECTNO> <SUBJECT>What are my reporting requirements under a non-arm's-length transportation arrangement?</SUBJECT> <P>(a) You or your affiliate must use a separate entry on Form MMS-2014 to notify MMS of an allowance based on transportation costs you or your affiliate incur.</P> <P>(b) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable oil transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems. Section 206.117 will apply when you amend your report based on your actual costs.</P> <P>(c) MMS may require you or your affiliate to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 207 of this chapter.</P> </SECTION> <SECTION> <SECTNO>§ 206.116</SECTNO> <SUBJECT>What interest and assessments apply if I improperly report a transportation allowance?</SUBJECT> <P>(a) If you or your affiliate net a transportation allowance rather than report it as a separate entry against the royalty value on Form MMS-2014, you will be assessed an amount up to 10 percent of the netted allowance, not to exceed $250 per lease selling arrangement per sales period.</P> <P>(b) If you or your affiliate deduct a transportation allowance on Form MMS-2014 that exceeds 50 percent of the value of the oil transported without obtaining MMS's prior approval under § 206.109, you must pay interest on the excess allowance amount taken from the date that amount is taken to the date you or your affiliate file an exception request that MMS approves. If you do not file an exception request, or if MMS does not approve your request, you must pay interest on the excess allowance amount taken from the date that amount is taken until the date you pay the additional royalties owed.</P> </SECTION> <SECTION> <SECTNO>§ 206.117</SECTNO> <SUBJECT>What reporting adjustments must I make for transportation allowances?</SUBJECT> <P>(a) If your or your affiliate's actual transportation allowance is less than the amount you claimed on Form MMS-2014 for each month during the allowance reporting period, you must pay additional royalties plus interest computed under 30 CFR 218.54 from the date you took the deduction to the date you repay the difference.</P> <P>(b) If the actual transportation allowance is greater than the amount you claimed on Form MMS-2014 for any month during the allowance form reporting period, you are entitled to a credit plus interest under applicable rules.</P> </SECTION> <SECTION> <SECTNO>§ 206.119</SECTNO> <SUBJECT>How are royalty quantity and quality determined?</SUBJECT> <P>(a) Compute royalties based on the quantity and quality of oil as measured at the point of settlement approved by BLM for onshore leases or MMS for offshore leases.</P> <P>(b) If the value of oil determined under this subpart is based upon a quantity or quality different from the quantity or quality at the point of royalty settlement approved by the BLM for onshore leases or MMS for offshore leases, adjust the value for those differences in quantity or quality.</P> <P>(c) Any actual loss that you may incur before the royalty settlement metering or measurement point is not subject to royalty if BLM or MMS, as <PRTPAGE P="81"/>appropriate, determines that the loss is unavoidable.</P> <P>(d) Except as provided in paragraph (b) of this section, royalties are due on 100 percent of the volume measured at the approved point of royalty settlement. You may not claim a reduction in that measured volume for actual losses beyond the approved point of royalty settlement or for theoretical losses that are claimed to have taken place either before or after the approved point of royalty settlement.</P> <CITA>[65 FR 14088, Mar. 15, 2000, as amended at 69 FR 24979, May 5, 2004]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.120</SECTNO> <SUBJECT>How are operating allowances determined?</SUBJECT> <P>MMS may use an operating allowance for the purpose of computing payment obligations when specified in the notice of sale and the lease. MMS will specify the allowance amount or formula in the notice of sale and in the lease agreement.</P> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart D—Federal Gas</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>53 FR 1272, Jan. 15, 1988, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 206.150</SECTNO> <SUBJECT>Purpose and scope.</SUBJECT> <P>(a) This subpart is applicable to all gas production from Federal oil and gas leases. The purpose of this subpart is to establish the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws and lease terms.</P> <P>(b) If the regulations in this subpart are inconsistent with:</P> <P>(1) A Federal statute;</P> <P>(2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation;</P> <P>(3) A written agreement between the lessee and the MMS Director establishing a method to determine the value of production from any lease that MMS expects at least would approximate the value established under this subpart; or</P> <P>(4) An express provision of an oil and gas lease subject to this subpart; then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency.</P> <P>(c) All royalty payments made to MMS are subject to audit and adjustment.</P> <P>(d) The regulations in this subpart are intended to ensure that the administration of oil and gas leases is discharged in accordance with the requirements of the governing mineral leasing laws and lease terms.</P> <CITA>[61 FR 5464, Feb. 12, 1996, as amended at 70 FR 11877, Mar. 10, 2005]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.151</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>For purposes of this subpart:</P> <P> <E T="03">Affiliate</E> means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:</P> <P>(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.</P> <P>(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:</P> <P>(i) The extent to which there are common officers or directors;</P> <P>(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: The percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;</P> <P>(iii) Operation of a lease, plant, pipeline, or other facility;</P> <P>(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, pipeline, or other facility; and</P> <P>(v) Other evidence of power to exercise control over or common control with another person.<PRTPAGE P="82"/> </P> <P>(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.</P> <P> <E T="03">Allowance</E> means a deduction in determining value for royalty purposes. <E T="03">Processing allowance</E> means an allowance for the reasonable, actual costs of processing gas determined under this subpart. <E T="03">Transportation allowance</E> means an allowance for the reasonable, actual costs of moving unprocessed gas, residue gas, or gas plant products to a point of sale or delivery off the lease, unit area, or communitized area, or away from a processing plant. The transportation allowance does not include gathering costs.</P> <P> <E T="03">Area</E> means a geographic region at least as large as the defined limits of an oil and/or gas field, in which oil and/or gas lease products have similar quality, economic, and legal characteristics.</P> <P> <E T="03">Arm's-length contract</E> means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.</P> <P> <E T="03">Audit</E> means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Federal leases.</P> <P> <E T="03">BLM</E> means the Bureau of Land Management of the Department of the Interior.</P> <P> <E T="03">Compression</E> means the process of raising the pressure of gas.</P> <P> <E T="03">Condensate</E> means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.</P> <P> <E T="03">Contract</E> means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.</P> <P> <E T="03">Field</E> means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields are usually given names and their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located. Outer Continental Shelf (OCS) fields are named and their boundaries are designated by MMS.</P> <P> <E T="03">Gas</E> means any fluid, either combustible or noncombustible, hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and which has neither independent shape nor volume, but tends to expand indefinitely. It is a substance that exists in a gaseous or rarefied state under standard temperature and pressure conditions.</P> <P> <E T="03">Gas plant products</E> means separate marketable elements, compounds, or mixtures, whether in liquid, gaseous, or solid form, resulting from processing gas, excluding residue gas.</P> <P> <E T="03">Gathering</E> means the movement of lease production to a central accumulation and/or treatment point on the lease, unit or communitized area, or to a central accumulation or treatment point off the lease, unit or communitized area as approved by BLM or MMS OCS operations personnel for onshore and OCS leases, respectively.</P> <P> <E T="03">Gross proceeds</E> (for royalty payment purposes) means the total monies and other consideration accruing to an oil and gas lessee for the disposition of the gas, residue gas, and gas plant products produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as dehydration, measurement, and/or gathering to the extent that the lessee is obligated to perform them at no cost to the Federal Government. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and other consideration, including the forms of <PRTPAGE P="83"/>consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.</P> <P> <E T="03">Lease</E> means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products—or the land area covered by that authorization, whichever is required by the context.</P> <P> <E T="03">Lease products</E> means any leased minerals attributable to, originating from, or allocated to Outer Continental Shelf or onshore Federal leases.</P> <P> <E T="03">Lessee</E> means any person to whom the United States issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.</P> <P> <E T="03">Like-quality lease products</E> means lease products which have similar chemical, physical, and legal characteristics.</P> <P> <E T="03">Marketable condition</E> means lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area.</P> <P> <E T="03">Marketing affiliate</E> means an affiliate of the lessee whose function is to acquire only the lessee's production and to market that production.</P> <P> <E T="03">Minimum royalty</E> means that minimum amount of annual royalty that the lessee must pay as specified in the lease or in applicable leasing regulations.</P> <P> <E T="03">Net-back method</E> (or work-back method) means a method for calculating market value of gas at the lease. Under this method, costs of transportation, processing, or manufacturing are deducted from the proceeds received for the gas, residue gas or gas plant products, and any extracted, processed, or manufactured products, or from the value of the gas, residue gas or gas plant products, and any extracted, processed, or manufactured products, at the first point at which reasonable values for any such products may be determined by a sale pursuant to an arm's-length contract or comparison to other sales of such products, to ascertain value at the lease.</P> <P> <E T="03">Net output</E> means the quantity of residue gas and each gas plant product that a processing plant produces.</P> <P> <E T="03">Net profit share</E> (for applicable Federal leases) means the specified share of the net profit from production of oil and gas as provided in the agreement.</P> <P> <E T="03">Netting</E> is the deduction of an allowance from the sales value by reporting a one line net sales value, instead of correctly reporting the deduction as a separate line item on the Form MMS-2014.</P> <P> <E T="03">Outer Continental Shelf (OCS)</E> means all submerged lands lying seaward and outside of the area of land beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.</P> <P> <E T="03">Person</E> means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).</P> <P> <E T="03">Posted price</E> means the price, net of all adjustments for quality and location, specified in publicly available price bulletins or other price notices available as part of normal business operations for quantities of unprocessed gas, residue gas, or gas plant products in marketable condition.</P> <P> <E T="03">Processing</E> means any process designed to remove elements or compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes which normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.</P> <P> <E T="03">Residue gas</E> means that hydrocarbon gas consisting principally of methane resulting from processing gas.<PRTPAGE P="84"/> </P> <P> <E T="03">Section 6 lease</E> means an OCS lease subject to section 6 of the Outer Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.</P> <P> <E T="03">Selling arrangement</E> means the individual contractual arrangements under which sales or dispositions of gas, residue gas and gas plant products are made. Selling arrangements are described by illustration in the MMS Royalty Management Program Oil and Gas Payor Handbook.</P> <P> <E T="03">Spot sales agreement</E> means a contract wherein a seller agrees to sell to a buyer a specified amount of unprocessed gas, residue gas, or gas plant products at a specified price over a fixed period, usually of short duration, which does not normally require a cancellation notice to terminate, and which does not contain an obligation, nor imply an intent, to continue in subsequent periods.</P> <P> <E T="03">Warranty contract</E> means a long-term contract entered into prior to 1970, including any amendments thereto, for the sale of gas wherein the producer agrees to sell a specific amount of gas and the gas delivered in satisfaction of this obligation may come from fields or sources outside of the designated fields.</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45084, Nov. 8, 1988; 61 FR 5464, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 70 FR 11878, Mar. 10, 2005]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.152</SECTNO> <SUBJECT>Valuation standards—unprocessed gas.</SUBJECT> <P>(a)(1) This section applies to the valuation of all gas that is not processed and all gas that is processed but is sold or otherwise disposed of by the lessee pursuant to an arm's-length contract prior to processing (including all gas where the lessee's arm's-length contract for the sale of that gas prior to processing provides for the value to be determined on the basis of a percentage of the purchaser's proceeds resulting from processing the gas). This section also applies to processed gas that must be valued prior to processing in accordance with § 206.155 of this part. Where the lessee's contract includes a reservation of the right to process the gas and the lessee exercises that right, § 206.153 of this part shall apply instead of this section.</P> <P>(2) The value of production, for royalty purposes, of gas subject to this subpart shall be the value of gas determined under this section less applicable allowances.</P> <P>(b)(1)(i) The value of gas sold under an arm's-length contract is the gross proceeds accruing to the lessee except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit. For purposes of this section, gas which is sold or otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate pursuant to an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate. Also, where the lessee's arm's-length contract for the sale of gas prior to processing provides for the value to be determined based upon a percentage of the purchaser's proceeds resulting from processing the gas, the value of production, for royalty purposes, shall never be less than a value equivalent to 100 percent of the value of the residue gas attributable to the processing of the lessee's gas.</P> <P>(ii) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the gas. If the contract does not reflect the total consideration, then the MMS may require that the gas sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration.</P> <P>(iii) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the gas production be valued pursuant to paragraph <PRTPAGE P="85"/>(c)(2) or (c)(3) of this section, and in accordance with the notification requirements of paragraph (e) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's value.</P> <P>(iv) <E T="03">How to value over-delivered volumes under a cash-out program.</E> This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (c)(3) of this section.</P> <P>(2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of gas sold pursuant to a warranty contract shall be determined by MMS, and due consideration will be given to all valuation criteria specified in this section. The lessee must request a value determination in accordance with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that any value determination for a warranty contract in effect on the effective date of these regulations shall remain in effect until modified by MMS.</P> <P>(3) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the gas.</P> <P>(c) The value of gas subject to this section which is not sold pursuant to an arm's-length contract shall be the reasonable value determined in accordance with the first applicable of the following methods:</P> <P>(1) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like-quality gas in the same field (or, if necessary to obtain a reasonable sample, from the same area). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of gas, volume, and such other factors as may be appropriate to reflect the value of the gas;</P> <P>(2) A value determined by consideration of other information relevant in valuing like-quality gas, including gross proceeds under arm's-length contracts for like-quality gas in the same field or nearby fields or areas, posted prices for gas, prices received in arm's-length spot sales of gas, other reliable public sources of price or market information, and other information as to the particular lease operation or the saleability of the gas; or</P> <P>(3) A net-back method or any other reasonable method to determine value.</P> <P>(d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the maximum price permitted by Federal law at which gas may be sold is less than the value determined pursuant to this section, then MMS shall accept such maximum price as the value. For purposes of this section, price limitations set by any State or local government shall not be considered as a maximum price permitted by Federal law.</P> <P>(2) The limitation prescribed in paragraph (d)(1) of this section shall not apply to gas sold pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section.</P> <P>(e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.<PRTPAGE P="86"/> </P> <P>(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Office of the Inspector General of the Department of the Interior, or other person authorized to receive such information, arm's-length sales and volume data for like-quality production sold, purchased or otherwise obtained by the lessee from the field or area or from nearby fields or areas.</P> <P>(3) A lessee shall notify MMS if it has determined value pursuant to paragraph (c)(2) or (c)(3) of this section. The notification shall be by letter to the MMS Associate Director for Minerals Revenue Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c)(2) or (c)(3) of this section, and each time there is a change in a method under paragraph (c)(2) or (c)(3) of this section.</P> <P>(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest on that difference computed pursuant to 30 CFR 218.54. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.</P> <P>(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination MMS may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.</P> <P>(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for lease production, less applicable allowances.</P> <P>(i) The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the gas in marketable condition or to market the gas.</P> <P>(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. If there is no contract revision or amendment, and the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of gas.</P> <P>(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or <PRTPAGE P="87"/>binding as against the Federal Government or its beneficiaries until the audit period is formally closed.</P> <P>(l) Certain information submitted to MMS to support valuation proposals, including transportation or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. § 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this subpart are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991; 61 FR 5464, Feb. 12, 1996; 62 FR 65761, 65762, Dec. 16, 1997]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.153</SECTNO> <SUBJECT>Valuation standards—processed gas.</SUBJECT> <P>(a)(1) This section applies to the valuation of all gas that is processed by the lessee and any other gas production to which this subpart applies and that is not subject to the valuation provisions of § 206.152 of this part. This section applies where the lessee's contract includes a reservation of the right to process the gas and the lessee exercises that right.</P> <P>(2) The value of production, for royalty purposes, of gas subject to this section shall be the combined value of the residue gas and all gas plant products determined pursuant to this section, plus the value of any condensate recovered downstream of the point of royalty settlement without resorting to processing determined pursuant to § 206.102 of this part, less applicable transportation allowances and processing allowances determined pursuant to this subpart.</P> <P>(b)(1)(i) The value of residue gas or any gas plant product sold under an arm's-length contract is the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value that the lessee reports for royalty purposes is subject to monitoring, review, and audit. For purposes of this section, residue gas or any gas plant product which is sold or otherwise transferred to the lessee's marketing affiliate and then sold by the marketing affiliate pursuant to an arm's-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate.</P> <P>(ii) In conducting these reviews and audits, MMS will examine whether or not the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the residue gas or gas plant product. If the contract does not reflect the total consideration, then the MMS may require that the residue gas or gas plant product sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration.</P> <P>(iii) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the residue gas or gas plant product because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the residue gas or gas plant product be valued pursuant to paragraph (c)(2) or (c)(3) of this section, and in accordance with the notification requirements of paragraph (e) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's value.</P> <P>(iv) <E T="03">How to value over-delivered volumes under a cash-out program.</E> This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price under the <PRTPAGE P="88"/>transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (c)(3) of this section.</P> <P>(2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of residue gas sold pursuant to a warranty contract shall be determined by MMS, and due consideration will be given to all valuation criteria specified in this section. The lessee must request a value determination in accordance with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that any value determination for a warranty contract in effect on the effective date of these regulations shall remain in effect until modified by MMS.</P> <P>(3) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the residue gas or gas plant product.</P> <P>(c) The value of residue gas or any gas plant product which is not sold pursuant to an arm's-length contract shall be the reasonable value determined in accordance with the first applicable of the following methods:</P> <P>(1) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like quality residue gas or gas plant products from the same processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of residue gas or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the residue gas or gas plant products;</P> <P>(2) A value determined by consideration of other information relevant in valuing like-quality residue gas or gas plant products, including gross proceeds under arm's-length contracts for like-quality residue gas or gas plant products from the same gas plant or other nearby processing plants, posted prices for residue gas or gas plant products, prices received in spot sales of residue gas or gas plant products, other reliable public sources of price or market information, and other information as to the particular lease operation or the saleability of such residue gas or gas plant products; or</P> <P>(3) A net-back method or any other reasonable method to determine value.</P> <P>(d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the maximum price permitted by Federal law at which any residue gas or gas plant products may be sold is less than the value determined pursuant to this section, then MMS shall accept such maximum price as the value. For the purposes of this section, price limitations set by any State or local government shall not be considered as a maximum price permitted by Federal law.</P> <P>(2) The limitation prescribed by paragraph (d)(1) of this section shall not apply to residue gas sold pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section.</P> <P>(e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines upon review or audit that the reported value is inconsistent with the requirements of these regulations.</P> <P>(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Office of the Inspector General of the Department of the Interior, or other persons authorized to receive such information, arm's-length sales and volume data for like-quality residue gas and gas plant products sold, purchased or otherwise obtained by the lessee from the same processing plant or from nearby processing plants.</P> <P>(3) A lessee shall notify MMS if it has determined any value pursuant to paragraph (c)(2) or (c)(3) of this section. <PRTPAGE P="89"/>The notification shall be by letter to the MMS Associate Director for Minerals Revenue Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a Form MMS-2014 using a valuation method authorized by paragraph (c)(2) or (c)(3) of this section, and each time there is a change in a method under paragraph (c)(2) or (c)(3) of this section.</P> <P>(f) If MMS determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also pay interest computed on that difference pursuant to 30 CFR 218.54. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.</P> <P>(g) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. In making a value determination, MMS may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section.</P> <P>(h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for residue gas and/or any gas plant products, less applicable transportation allowances and processing allowances determined pursuant to this subpart.</P> <P>(i) The lessee must place residue gas and gas plant products in marketable condition and market the residue gas and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the residue gas or gas plant products in marketable condition or to market the residue gas and gas plant products.</P> <P>(j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part, or timely, for a quantity of residue gas or gas plant product.</P> <P>(k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding against the Federal Government or its beneficiaries until the audit period is formally closed.</P> <P>(l) Certain information submitted to MMS to support valuation proposals, including transportation allowances, processing allowances or extraordinary <PRTPAGE P="90"/>cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 56 FR 46530, Sept. 13, 1991; 61 FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.154</SECTNO> <SUBJECT>Determination of quantities and qualities for computing royalties.</SUBJECT> <P>(a)(1) Royalties shall be computed on the basis of the quantity and quality of unprocessed gas at the point of royalty settlement approved by BLM or MMS for onshore and OCS leases, respectively.</P> <P>(2) If the value of gas determined pursuant to § 206.152 of this subpart is based upon a quantity and/or quality that is different from the quantity and/or quality at the point of royalty settlement, as approved by BLM or MMS, that value shall be adjusted for the differences in quantity and/or quality.</P> <P>(b)(1) For residue gas and gas plant products, the quantity basis for computing royalties due is the monthly net output of the plant even though residue gas and/or gas plant products may be in temporary storage.</P> <P>(2) If the value of residue gas and/or gas plant products determined pursuant to § 206.153 of this subpart is based upon a quantity and/or quality of residue gas and/or gas plant products that is different from that which is attributable to a lease, determined in accordance with paragraph (c) of this section, that value shall be adjusted for the differences in quantity and/or quality.</P> <P>(c) The quantity of the residue gas and gas plant products attributable to a lease shall be determined according to the following procedure:</P> <P>(1) When the net output of the processing plant is derived from gas obtained from only one lease, the quantity of the residue gas and gas plant products on which computations of royalty are based is the net output of the plant.</P> <P>(2) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to each lease shall be in the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases.</P> <P>(3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of nonuniform content, the quantity of the residue gas allocable to each lease will be determined by multiplying the amount of gas delivered to the plant from the lease by the residue gas content of the gas, and dividing the arithmetical product thus obtained by the sum of the similar arithmetical products separately obtained for all leases from which gas is delivered to the plant, and then multiplying the net output of the residue gas by the arithmetic quotient obtained. The net output of gas plant products allocable to each lease will be determined by multiplying the amount of gas delivered to the plant from the lease by the gas plant product content of the gas, and dividing the arithmetical product thus obtained by the sum of the similar arithmetical products separately obtained for all leases from which gas is delivered to the plant, and then multiplying the net output of each gas plant product by the arithmetic quotient obtained.</P> <P>(4) A lessee may request MMS approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If approved, such method will be applicable to all gas production from Federal leases that is processed in the same plant.</P> <P>(d)(1) No deductions may be made from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas that may be sustained prior to the royalty settlement metering or measurement point will not be subject to royalty provided that such loss is determined <PRTPAGE P="91"/>to have been unavoidable by BLM or MMS, as appropriate.</P> <P>(2) Except as provided in paragraph (d)(1) of this section and 30 CFR 202.151(c), royalties are due on 100 percent of the volume determined in accordance with paragraphs (a) through (c) of this section. There can be no reduction in that determined volume for actual losses after the quantity basis has been determined or for theoretical losses that are claimed to have taken place. Royalties are due on 100 percent of the value of the unprocessed gas, residue gas, and/or gas plant products as provided in this subpart, less applicable allowances. There can be no deduction from the value of the unprocessed gas, residue gas, and/or gas plant products to compensate for actual losses after the quantity basis has been determined, or for theoretical losses that are claimed to have taken place.</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.155</SECTNO> <SUBJECT>Accounting for comparison.</SUBJECT> <P>(a) Except as provided in paragraph (b) of this section, where the lessee (or a person to whom the lessee has transferred gas pursuant to a non-arm's-length contract or without a contract) processes the lessee's gas and after processing the gas the residue gas is not sold pursuant to an arm's-length contract, the value, for royalty purposes, shall be the greater of (1) the combined value, for royalty purposes, of the residue gas and gas plant products resulting from processing the gas determined pursuant to § 206.153 of this subpart, plus the value, for royalty purposes, of any condensate recovered downstream of the point of royalty settlement without resorting to processing determined pursuant to § 206.102 of this subpart; or (2) the value, for royalty purposes, of the gas prior to processing determined in accordance with § 206.152 of this subpart.</P> <P>(b) The requirement for accounting for comparison contained in the terms of leases will govern as provided in § 206.150(b) of this subpart. When accounting for comparison is required by the lease terms, such accounting for comparison shall be determined in accordance with paragraph (a) of this section.</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.156</SECTNO> <SUBJECT>Transportation allowances—general.</SUBJECT> <P>(a) Where the value of gas has been determined pursuant to § 206.152 or § 206.153 of this subpart at a point (e.g., sales point or point of value determination) off the lease, MMS shall allow a deduction for the reasonable actual costs incurred by the lessee to transport unprocessed gas, residue gas, and gas plant products from a lease to a point off the lease including, if appropriate, transportation from the lease to a gas processing plant off the lease and from the plant to a point away from the plant.</P> <P>(b) Transportation costs must be allocated among all products produced and transported as provided in § 206.157.</P> <P>(c)(1) Except as provided in paragraph (c)(3) of this section, for unprocessed gas valued in accordance with § 206.152 of this subpart, the transportation allowance deduction on the basis of a selling arrangement shall not exceed 50 percent of the value of the unprocessed gas determined in accordance with § 206.152 of this subpart.</P> <P>(2) Except as provided in paragraph (c)(3) of this section, for gas production valued in accordance with § 206.153 of this subpart the transportation allowance deduction on the basis of a selling arrangement shall not exceed 50 percent of the value of the residue gas or gas plant product determined in accordance with § 206.153 of this subpart. For purposes of this section, natural gas liquids shall be considered one product.</P> <P>(3) Upon request of a lessee, MMS may approve a transportation allowance deduction in excess of the limitations prescribed by paragraphs (c)(1) and (c)(2) of this section. The lessee must demonstrate that the transportation costs incurred in excess of the limitations prescribed in paragraphs (c)(1) and (c)(2) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) shall contain all relevant and supporting <PRTPAGE P="92"/>documentation necessary for MMS to make a determination. Under no circumstances shall the value for royalty purposes under any selling arrangement be reduced to zero.</P> <P>(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this subpart, then the lessee shall pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.54, or shall be entitled to a credit, without interest. If the lessee takes a deduction for transportation on the Form MMS-2014 by improperly netting the allowance against the sales value of the unprocessed gas, residue gas, and gas plant products instead of reporting the allowance as a separate line item, he may be assessed an additional amount under 206.157(d).</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5465, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.157</SECTNO> <SUBJECT>Determination of transportation allowances.</SUBJECT> <P>(a) <E T="03">Arm's-length transportation contracts.</E> (1)(i) For transportation costs incurred by a lessee under an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the unprocessed gas, residue gas and/or gas plant products under that contract, except as provided in paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to monitoring, review, audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. Such allowances shall be subject to the provisions of paragraph (f) of this section. The lessee must claim a transportation allowance by reporting it as a separate line entry on the Form MMS-2014.</P> <P>(ii) In conducting reviews and audits, MMS will examine whether or not the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration, then the MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.</P> <P>(iii) If the MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.</P> <P>(2)(i) If an arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract, the total transportation costs shall be allocated in a consistent and equitable manner to each of the products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, no allowance may be taken for the costs of transporting lease production which is not royalty bearing without MMS approval.</P> <P>(ii) Notwithstanding the requirements of paragraph (i), the lessee may propose to MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.</P> <P>(3) If an arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use the transportation allowance determined <PRTPAGE P="93"/>in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. MMS shall then determine the gas transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on the Form MMS-2014.</P> <P>(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar per unit, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.</P> <P>(5) Where an arm's-length sales contract price or a posted price includes a provision whereby the listed price is reduced by a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. The transportation factor may be used in determining the lessee's gross proceeds for the sale of the product. The transportation factor may not exceed 50 percent of the base price of the product without MMS approval.</P> <P>(b) <E T="03">Non-arm's-length or no contract.</E> (1) If a lessee has a non-arm's-length transportation contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable actual costs as provided in this paragraph. All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and adjustment. The lessee must claim a transportation allowance by reporting it as a separate line entry on the Form MMS-2014. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual transportation allowance deduction.</P> <P>(2) The transportation allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.</P> <P>(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.</P> <P>(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.</P> <P>(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of the MMS.</P> <P>(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.<PRTPAGE P="94"/> </P> <P>(B) The MMS shall allow as a cost an amount equal to the allowable initial capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service after March 1, 1988.</P> <P>(v) The rate of return must be 1.3 times the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.</P> <P>(3)(i) The deduction for transportation costs shall be determined on the basis of the lessee's cost of transporting each product through each individual transportation system. Where more than one product in a gaseous phase is transported, the allocation of costs to each of the products transported shall be made in a consistent and equitable manner in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, the lessee may not take an allowance for transporting a product which is not royalty bearing without MMS approval.</P> <P>(ii) Notwithstanding the requirements of paragraph (b)(3)(i), the lessee may propose to the MMS a cost allocation method on the basis of the values of the products transported. MMS shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part.</P> <P>(4) Where both gaseous and liquid products are transported through the same transportation system, the lessee shall propose a cost allocation procedure to MMS. The lessee may use the transportation allowance determined in accordance with its proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. MMS shall then determine the transportation allowance based upon the lessee's proposal and any additional information MMS deems necessary. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on the Form MMS-2014.</P> <P>(5) You may apply for an exception from the requirement to compute actual costs under paragraphs (b)(1) through (b)(4) of this section.</P> <P>(i) The MMS will grant the exception if:</P> <P>(A) The transportation system has a tariff filed with the Federal Energy Regulatory Commission (FERC) or a state regulatory agency, that FERC or the state regulatory agency has permitted to become effective, and</P> <P>(B) Third parties are paying prices, including discounted prices, under the tariff to transport gas on the system under arm's-length transportation contracts.</P> <P>(ii) If MMS approves the exception, you must calculate your transportation allowance for each production month based on the lesser of the volume-weighted average of the rates paid by the third parties under arm's-length transportation contracts during that production month or the non-arm's-length payment by the lessee to the pipeline.</P> <P>(iii) If during any production month there are no prices paid under the tariff by third parties to transport gas on the system under arm's-length transportation contracts, you may use the volume-weighted average of the rates paid by third parties under arm's-length transportation contracts in the most recent preceding production month in which the tariff remains in effect and third parties paid such rates, for up to five successive production months. You must use the non-arm's-length payment by the lessee to the pipeline if it is less than the volume-weighted average of the rates paid by third parties under arm's-length contracts.</P> <P>(c) <E T="03">Reporting requirements</E>—(1) <E T="03">Arm's-length contracts.</E> (i) You must use a separate entry on Form MMS-2014 to notify MMS of a transportation allowance.<PRTPAGE P="95"/> </P> <P>(ii) The MMS may require you to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 207 of this chapter.</P> <P>(iii) You may not use a transportation allowance that was in effect before March 1, 1988. You must use the provisions of this subpart to determine your transportation allowance.</P> <P>(2) <E T="03">Non-arm's-length or no contract.</E> (i) You must use a separate entry on Form MMS-2014 to notify MMS of a transportation allowance.</P> <P>(ii) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable gas transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems. Paragraph (e) of this section will apply when you amend your report based on your actual costs.</P> <P>(iii) The MMS may require you to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 207 of this chapter.</P> <P>(iv) If you are authorized under paragraph (b)(5) of this section to use an exception to the requirement to calculate your actual transportation costs, you must follow the reporting requirements of paragraph (c)(1) of this section.</P> <P>(v) You may not use a transportation allowance that was in effect before March 1, 1988. You must use the provisions of this subpart to determine your transportation allowance.</P> <P>(d) <E T="03">Interest and assessments.</E> (1) If a lessee nets a transportation allowance against the royalty value on the Form MMS-2014, the lessee shall be assessed an amount of up to 10 percent of the allowance netted not to exceed $250 per lease selling arrangement per sales period.</P> <P>(2) If a lessee deducts a transportation allowance on its Form MMS-2014 that exceeds 50 percent of the value of the gas transported without obtaining prior approval of MMS under § 206.156, the lessee shall pay interest on the excess allowance amount taken from the date such amount is taken to the date the lessee files an exception request with MMS.</P> <P>(3) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.</P> <P>(4) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.</P> <P>(e) <E T="03">Adjustments.</E> (1) If the actual transportation allowance is less than the amount the lessee has taken on Form MMS-2014 for each month during the allowance reporting period, the lessee shall be required to pay additional royalties due plus interest computed under 30 CFR 218.54 from the allowance reporting period when the lessee took the deduction to the date the lessee repays the difference to MMS. If the actual transportation allowance is greater than the amount the lessee has taken on Form MMS-2014 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.</P> <P>(2) For lessees transporting production from onshore Federal leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.</P> <P>(3) For lessees transporting gas production from leases on the OCS, if the lessee's estimated transportation allowance exceeds the allowance based on actual costs, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with its payment, in accordance with instructions provided by MMS. If the lessee's estimated transportation allowance is less than the allowance based on actual costs, the refund procedure will be specified by MMS.</P> <P>(f) <E T="03">Allowable costs in determining transportation allowances.</E> You may include, but are not limited to (subject to the requirements of paragraph (g) of this section), the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section. You may not <PRTPAGE P="96"/>use any cost as a deduction that duplicates all or part of any other cost that you use under this paragraph.</P> <P>(1) <E T="03">Firm demand charges paid to pipelines.</E> You may deduct firm demand charges or capacity reservation fees paid to a pipeline, including charges or fees for unused firm capacity that you have not sold before you report your allowance. If you receive a payment from any party for release or sale of firm capacity after reporting a transportation allowance that included the cost of that unused firm capacity, or if you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the Form MMS-2014 by the amount of that payment. You must modify the Form MMS-2014 by the amount received or credited for the affected reporting period, and pay any resulting royalty and late payment interest due;</P> <P>(2) <E T="03">Gas supply realignment (GSR) costs.</E> The GSR costs result from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC Orders in 18 CFR part 284;</P> <P>(3) <E T="03">Commodity charges.</E> The commodity charge allows the pipeline to recover the costs of providing service;</P> <P>(4) <E T="03">Wheeling costs.</E> Hub operators charge a wheeling cost for transporting gas from one pipeline to either the same or another pipeline through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines;</P> <P>(5) <E T="03">Gas Research Institute (GRI) fees.</E> The GRI conducts research, development, and commercialization programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers. GRI fees are allowable provided such fees are mandatory in FERC-approved tariffs;</P> <P>(6) <E T="03">Annual Charge Adjustment (ACA) fees.</E> FERC charges these fees to pipelines to pay for its operating expenses;</P> <P>(7) <E T="03">Payments (either volumetric or in value) for actual or theoretical losses.</E> However, theoretical losses are not deductible in non-arm's-length transportation arrangements unless the transportation allowance is based on arm's-length transportation rates charged under a FERC- or state regulatory-approved tariff under paragraph (b)(5) of this section. If you receive volumes or credit for line gain, you must reduce your transportation allowance accordingly and pay any resulting royalties and late payment interest due;</P> <P>(8) <E T="03">Temporary storage services.</E> This includes short duration storage services offered by market centers or hubs (commonly referred to as “parking” or “banking”), or other temporary storage services provided by pipeline transporters, whether actual or provided as a matter of accounting. Temporary storage is limited to 30 days or less; and</P> <P>(9) <E T="03">Supplemental costs for compression, dehydration, and treatment of gas.</E> MMS allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under §§ 206.152(i) and 206.153(i) of this part.</P> <P>(10) <E T="03">Costs of surety.</E> You may deduct the costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to maintain under an arm's-length transportation contract.</P> <P>(g) <E T="03">Nonallowable costs in determining transportation allowances.</E> Lessees may not include the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section:</P> <P>(1) <E T="03">Fees or costs incurred for storage.</E> This includes storing production in a storage facility, whether on or off the lease, for more than 30 days;</P> <P>(2) <E T="03">Aggregator/marketer fees.</E> This includes fees you pay to another person (including your affiliates) to market your gas, including purchasing and reselling the gas, or finding or maintaining a market for the gas production;</P> <P>(3) <E T="03">Penalties you incur as shipper.</E> These penalties include, but are not limited to:</P> <P>(i) <E T="03">Over-delivery cash-out penalties.</E> This includes the difference between the price the pipeline pays you for over-delivered volumes outside the tolerances and the price you receive for <PRTPAGE P="97"/>over-delivered volumes within the tolerances;</P> <P>(ii) <E T="03">Scheduling penalties.</E> This includes penalties you incur for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point;</P> <P>(iii) <E T="03">Imbalance penalties.</E> This includes penalties you incur (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point; and</P> <P>(iv) <E T="03">Operational penalties.</E> This includes fees you incur for violation of the pipeline's curtailment or operational orders issued to protect the operational integrity of the pipeline;</P> <P>(4) <E T="03">Intra-hub transfer fees.</E> These are fees you pay to hub operators for administrative services (e.g., title transfer tracking) necessary to account for the sale of gas within a hub;</P> <P>(5) <E T="03">Fees paid to brokers.</E> This includes fees paid to parties who arrange marketing or transportation, if such fees are separately identified from aggregator/marketer fees;</P> <P>(6) <E T="03">Fees paid to scheduling service providers.</E> This includes fees paid to parties who provide scheduling services, if such fees are separately identified from aggregator/marketer fees;</P> <P>(7) <E T="03">Internal costs.</E> This includes salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production; and</P> <P>(8) <E T="03">Other nonallowable costs.</E> Any cost you incur for services you are required to provide at no cost to the lessor.</P> <P>(h) <E T="03">Other transportation cost determinations.</E> Use this section when calculating transportation costs to establish value using a netback procedure or any other procedure that requires deduction of transportation costs.</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 FR 5465, Feb. 12, 1996; 62 FR 65762, Dec. 16, 1997; 70 FR 11878, Mar. 10, 2005]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.158</SECTNO> <SUBJECT>Processing allowances—general.</SUBJECT> <P>(a) Where the value of gas is determined pursuant to § 206.153 of this subpart, a deduction shall be allowed for the reasonable actual costs of processing.</P> <P>(b) Processing costs must be allocated among the gas plant products. A separate processing allowance must be determined for each gas plant product and processing plant relationship. Natural gas liquids (NGL's) shall be considered as one product.</P> <P>(c)(1) Except as provided in paragraph (d)(2) of this section, the processing allowance shall not be applied against the value of the residue gas. Where there is no residue gas MMS may designate an appropriate gas plant product against which no allowance may be applied.</P> <P>(2) Except as provided in paragraph (c)(3) of this section, the processing allowance deduction on the basis of an individual product shall not exceed 66<FR>2/3</FR> percent of the value of each gas plant product determined in accordance with § 206.153 of this subpart (such value to be reduced first for any transportation allowances related to postprocessing transportation authorized by § 206.156 of this subpart).</P> <P>(3) Upon request of a lessee, MMS may approve a processing allowance in excess of the limitation prescribed by paragraph (c)(2) of this section. The lessee must demonstrate that the processing costs incurred in excess of the limitation prescribed in paragraph (c)(2) of this section were reasonable, actual, and necessary. An application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) shall contain all relevant and supporting documentation for MMS to make a determination. Under no circumstances shall the value for royalty purposes of any gas plant product be reduced to zero.</P> <P>(d)(1) Except as provided in paragraph (d)(2) of this section, no processing cost deduction shall be allowed for the costs of placing lease products in marketable condition, including dehydration, separation, compression, or storage, even if those functions are performed off the lease or at a processing plant. Where gas is processed for the removal of acid gases, commonly referred to as “sweetening,” no processing cost deduction shall be allowed for such costs unless the acid gases removed are further processed into a gas <PRTPAGE P="98"/>plant product. In such event, the lessee shall be eligible for a processing allowance as determined in accordance with this subpart. However, MMS will not grant any processing allowance for processing lease production which is not royalty bearing.</P> <P>(2)(i) If the lessee incurs extraordinary costs for processing gas production from a gas production operation, it may apply to MMS for an allowance for those costs which shall be in addition to any other processing allowance to which the lessee is entitled pursuant to this section. Such an allowance may be granted only if the lessee can demonstrate that the costs are, by reference to standard industry conditions and practice, extraordinary, unusual, or unconventional.</P> <P>(ii) Prior MMS approval to continue an extraordinary processing cost allowance is not required. However, to retain the authority to deduct the allowance the lessee must report the deduction to MMS in a form and manner prescribed by MMS.</P> <P>(e) If MMS determines that a lessee has improperly determined a processing allowance authorized by this subpart, then the lessee shall pay any additional royalties, plus interest determined in accordance with 30 CFR 218.54, or shall be entitled to a credit, without interest. If the lessee takes a deduction for processing on the Form MMS-2014 by improperly netting the allowance against the sales value of the gas plant products instead of reporting the allowance as a separate line item, he may be assessed an additional amount under 206.159(d).</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 61 FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.159</SECTNO> <SUBJECT>Determination of processing allowances.</SUBJECT> <P>(a) <E T="03">Arm's-length processing contracts.</E> (1)(i) For processing costs incurred by a lessee under an arm's-length contract, the processing allowance shall be the reasonable actual costs incurred by the lessee for processing the gas under that contract, except as provided in paragraphs (a)(1)(ii) and (a)(1)(iii) of this section, subject to monitoring, review, audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. The lessee must claim a processing allowance by reporting it as a separate line entry on the Form MMS-2014.</P> <P>(ii) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the processor for the processing. If the contract reflects more than the total consideration, then the MMS may require that the processing allowance be determined in accordance with paragraph (b) of this section.</P> <P>(iii) If MMS determines that the consideration paid pursuant to an arm's-length processing contract does not reflect the reasonable value of the processing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and lessor, then MMS shall require that the processing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the processing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's processing costs.</P> <P>(2) If an arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product can be determined from the contract, then the processing costs for each gas plant product shall be determined in accordance with the contract. No allowance may be taken for the costs of processing lease production which is not royalty-bearing.</P> <P>(3) If an arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product cannot be determined from the contract, the lessee shall propose an allocation procedure to MMS. The lessee may use its proposed allocation procedure until MMS issues its determination. The lessee shall submit all relevant data to support its proposal. MMS shall then <PRTPAGE P="99"/>determine the processing allowance based upon the lessee's proposal and any additional information MMS deems necessary. No processing allowance will be granted for the costs of processing lease production which is not royalty bearing. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on Form MMS-2014.</P> <P>(4) Where the lessee's payments for processing under an arm's-length contract are not based on a dollar per unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.</P> <P>(b) <E T="03">Non-arm's-length or no contract.</E> (1) If a lessee has a non-arm's-length processing contract or has no contract, including those situations where the lessee performs processing for itself, the processing allowance will be based upon the lessee's reasonable actual costs as provided in this paragraph. All processing allowances deducted under a non-arm's-length or no-contract situation are subject to monitoring, review, audit, and adjustment. The lessee must claim a processing allowance by reflecting it as a separate line entry on the Form MMS-2014. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual processing allowance.</P> <P>(2) The processing allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for processing during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the processing plant.</P> <P>(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.</P> <P>(ii) Allowable maintenance expenses include: Maintenance of the processing plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.</P> <P>(iii) Overhead directly attributable and allocable to the operation and maintenance of the processing plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.</P> <P>(iv) A lessee may use either depreciation or a return on depreciable capital investment. When a lessee has elected to use either method for a processing plant, the lessee may not later elect to change to the other alternative without approval of the MMS.</P> <P>(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the processing plant services, or a unit-of-production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a processing plant shall not alter the depreciation schedule established by the original processor/lessee for purposes of the allowance calculation. With or without a change in ownership, a processing plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.</P> <P>(B) The MMS shall allow as a cost an amount equal to the allowable initial capital investment in the processing plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service after March 1, 1988.</P> <P>(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The <PRTPAGE P="100"/>rate must be redetermined at the beginning of each subsequent calendar year.</P> <P>(3) The processing allowance for each gas plant product shall be determined based on the lessee's reasonable and actual cost of processing the gas. Allocation of costs to each gas plant product shall be based upon generally accepted accounting principles. The lessee may not take an allowance for the costs of processing lease production which is not royalty bearing.</P> <P>(4) A lessee may apply to MMS for an exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) through (b)(3) of this section. The MMS may grant the exception only if: (i) The lessee has arm's-length contracts for processing other gas production at the same processing plant; and (ii) at least 50 percent of the gas processed annually at the plant is processed pursuant to arm's-length processing contracts; if the MMS grants the exception, the lessee shall use as its processing allowance the volume weighted average prices charged other persons pursuant to arm's-length contracts for processing at the same plant.</P> <P>(c) <E T="03">Reporting requirements</E>—(1) <E T="03">Arm's-length contracts.</E> (i) The lessee must notify MMS of an allowance based on incurred costs by using a separate line entry on the Form MMS-2014.</P> <P>(ii) The MMS may require that a lessee submit arm's-length processing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.</P> <P>(2) <E T="03">Non-arm's-length or no contract.</E> (i) The lessee must notify MMS of an allowance based on the incurred costs by using a separate line entry on the Form MMS-2014.</P> <P>(ii) For new processing plants, the lessee's initial deduction shall include estimates of the allowable gas processing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant or, if such data are not available, the lessee shall use estimates based upon industry data for similar gas processing plants.</P> <P>(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.</P> <P>(iv) If the lessee is authorized to use the volume weighted average prices charged other persons as its processing allowance in accordance with paragraph (b)(4) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.</P> <P>(d) <E T="03">Interest and assessments.</E> (1) If a lessee nets a processing allowance against the royalty value on the Form MMS-2014, the lessee shall be assessed an amount of up to 10 percent of the allowance netted not to exceed $250 per lease selling arrangement per sales period.</P> <P>(2) If a lessee deducts a processing allowance on its Form MMS-2014 that exceeds 66<FR>2/3</FR> percent of the value of the gas processed without obtaining prior approval of MMS under § 206.158, the lessee shall pay interest on the excess allowance amount taken from the date such amount is taken to the date the lessee files an exception request with MMS.</P> <P>(3) If a lessee erroneously reports a processing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.</P> <P>(4) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.54.</P> <P>(e) <E T="03">Adjustments.</E> (1) If the actual processing allowance is less than the amount the lessee has taken on Form MMS-2014 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under 30 CFR 218.54 from the allowance reporting period when the lessee took the deduction to the date the lessee repays the difference to MMS. If the actual processing allowance is greater than the amount the lessee has taken on Form MMS-2014 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.</P> <P>(2) For lessees processing production from onshore Federal leases, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.<PRTPAGE P="101"/> </P> <P>(3) For lessees processing gas production from leases on the OCS, if the lessee's estimated processing allowance exceeds the allowance based on actual costs, the lessee must submit a corrected Form MMS-2014 to reflect actual costs, together with its payment, in accordance with instructions provided by MMS. If the lessee's estimated costs were less than the actual costs, the refund procedure will be specified by MMS.</P> <P>(f) <E T="03">Other processing cost determinations.</E> The provisions of this section shall apply to determine processing costs when establishing value using a net back valuation procedure or any other procedure that requires deduction of processing costs.</P> <CITA>[53 FR 1272, Jan. 15, 1988, as amended at 53 FR 45762, Nov. 14, 1988; 61 FR 5466, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.160</SECTNO> <SUBJECT>Operating allowances.</SUBJECT> <P>Notwithstanding any other provisions in these regulations, an operating allowance may be used for the purpose of computing payment obligations when specified in the notice of sale and the lease. The allowance amount or formula shall be specified in the notice of sale and in the lease agreement.</P> <CITA>[61 FR 3804, Feb. 2, 1996]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Indian Gas</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>64 FR 43515, Aug. 10, 1999, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 206.170</SECTNO> <SUBJECT>What does this subpart contain?</SUBJECT> <P>This subpart contains royalty valuation provisions applicable to Indian lessees.</P> <P>(a) This subpart applies to all gas production from Indian (tribal and allotted) oil and gas leases (except leases on the Osage Indian Reservation). The purpose of this subpart is to establish the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms. This subpart does not apply to Federal leases.</P> <P>(b) If the specific provisions of any Federal statute, treaty, negotiated agreement, settlement agreement resulting from any administrative or judicial proceeding, or Indian oil and gas lease are inconsistent with any regulation in this subpart, then the Federal statute, treaty, negotiated agreement, settlement agreement, or lease will govern to the extent of that inconsistency.</P> <P>(c) You may calculate the value of production for royalty purposes under methods other than those the regulations in this title require, but only if you, the tribal lessor, and MMS jointly agree to the valuation methodology. For leases on Indian allotted lands, you and MMS must agree to the valuation methodology.</P> <P>(d) All royalty payments you make to MMS are subject to monitoring, review, audit, and adjustment.</P> <P>(e) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian oil and gas leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.</P> </SECTION> <SECTION> <SECTNO>§ 206.171</SECTNO> <SUBJECT>What definitions apply to this subpart?</SUBJECT> <P>The following definitions apply to this subpart and to subpart J of part 202 of this title:</P> <P> <E T="03">Accounting for comparison</E> means the same as dual accounting.</P> <P> <E T="03">Active spot market</E> means a market where one or more MMS-acceptable publications publish bidweek prices (or if bidweek prices are not available, first of the month prices) for at least one index-pricing point in the index zone.</P> <P> <E T="03">Allowance</E> means a deduction in determining value for royalty purposes. Processing allowance means an allowance for the reasonable, actual costs of processing gas determined under this subpart. Transportation allowance means an allowance for the reasonable, actual cost of transportation determined under this subpart.</P> <P> <E T="03">Approved Federal Agreement (AFA)</E> means a unit or communitization agreement approved under departmental regulations.</P> <P> <E T="03">Area</E> means a geographic region at least as large as the defined limits of an oil or gas field, in which oil or gas lease products have similar quality, <PRTPAGE P="102"/>economic, or legal characteristics. An area may be all lands within the boundaries of an Indian reservation.</P> <P> <E T="03">Arm's-length contract</E> means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. The following percentages (based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership) determine if persons are affiliated:</P> <P>(1) Ownership in excess of 50 percent constitutes control.</P> <P>(2) Ownership of 10 through 50 percent creates a presumption of control.</P> <P>(3) Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. MMS may require the lessee to certify the percentage of ownership or control of the entity. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month as well as when the contract was executed.</P> <P> <E T="03">Audit</E> means a review, conducted under generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other persons who pay royalties, rents, or bonuses on Indian leases.</P> <P> <E T="03">BIA</E> means the Bureau of Indian Affairs of the Department of the Interior.</P> <P> <E T="03">BLM</E> means the Bureau of Land Management of the Department of the Interior.</P> <P> <E T="03">Compression</E> means raising the pressure of gas.</P> <P> <E T="03">Condensate</E> means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir.</P> <P> <E T="03">Contract</E> means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.</P> <P> <E T="03">Dedicated</E> means a contractual commitment to deliver gas production (or a specified portion of production) from a lease or well when that production is specified in a sales contract <E T="03">and</E> that production must be sold pursuant to that contract to the extent that production occurs from that lease or well.</P> <P> <E T="03">Drip condensate</E> means any condensate recovered downstream of the facility measurement point without resorting to processing. Drip condensate includes condensate recovered as a result of its becoming a liquid during the transportation of the gas removed from the lease or recovered at the inlet of a gas processing plant by mechanical means, often referred to as scrubber condensate.</P> <P> <E T="03">Dual Accounting</E> (or <E T="03">accounting for comparison</E>) refers to the requirement to pay royalty based on a value which is the higher of the value of gas prior to processing less any applicable allowances as compared to the combined value of drip condensate, residue gas, and gas plant products after processing, less applicable allowances.</P> <P> <E T="03">Entitlement</E> (or <E T="03">entitled share</E>) means the gas production from a lease, or allocable to lease acreage under the terms of an AFA, multiplied by the operating rights owner's percentage of interest ownership in the lease or the acreage.</P> <P> <E T="03">Facility measurement point</E> (or <E T="03">point of royalty settlement</E>) means the point where the BLM-approved measurement device is located for determining the volume of gas removed from the lease. The facility measurement point may be on the lease or off-lease with BLM approval.</P> <P> <E T="03">Field</E> means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields are usually given names and <PRTPAGE P="103"/>their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located.</P> <P> <E T="03">Gas</E> means any fluid, either combustible or noncombustible, hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and which has neither independent shape nor volume, but tends to expand indefinitely. It is a substance that exists in a gaseous or rarefied state under standard temperature and pressure conditions.</P> <P> <E T="03">Gas plant products</E> means separate marketable elements, compounds, or mixtures, whether in liquid, gaseous, or solid form, resulting from processing gas. However, it does not include residue gas.</P> <P> <E T="03">Gathering</E> means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area; or a central accumulation or treatment point off the lease, unit, or communitized area as approved by BLM operations personnel.</P> <P> <E T="03">Gross proceeds</E> (for royalty payment purposes) means the total monies and other consideration accruing to an oil and gas lessee for the disposition of unprocessed gas, residue gas, and gas plant products produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as compression, dehydration, measurement, or field gathering to the extent that the lessee is obligated to perform them at no cost to the Indian lessor, and payments for gas processing rights. Gross proceeds, as applied to gas, also includes but is not limited to reimbursements for severance taxes and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Indian royalty interest is exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.</P> <P> <E T="03">Index</E> means the calculated composite price ($/MMBtu) of spot-market sales published by a publication that meets MMS-established criteria for acceptability at the index-pricing point.</P> <P> <E T="03">Index-pricing point</E> (IPP) means any point on a pipeline for which there is an index.</P> <P> <E T="03">Index zone</E> means a field or an area with an active spot market and published indices applicable to that field or area that are acceptable to MMS under § 206.172(d)(2).</P> <P> <E T="03">Indian allottee</E> means any Indian for whom land or an interest in land is held in trust by the United States or who holds title subject to Federal restriction against alienation.</P> <P> <E T="03">Indian tribe</E> means any Indian tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any land or interest in land is held in trust by the United States or which is subject to Federal restriction against alienation.</P> <P> <E T="03">Lease</E> means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products—or the land area covered by that authorization, whichever is required by the context. For purposes of this subpart, this definition excludes Federal leases.</P> <P> <E T="03">Lease products</E> means any leased minerals attributable to, originating from, or allocated to a lease.</P> <P> <E T="03">Lessee</E> means any person to whom the United States, a tribe, and/or individual Indian landowner issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease (including operating rights owners) as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.</P> <P> <E T="03">Like-quality lease products</E> means lease products which have similar chemical, physical, and legal characteristics.</P> <P> <E T="03">Marketable condition</E> means a condition in which lease products are sufficiently free from impurities and otherwise so conditioned that a purchaser will accept them under a sales contract typical for the field or area.</P> <P> <E T="03">MMS</E> means the Minerals Management Service, Department of the Interior. MMS includes, where appropriate, <PRTPAGE P="104"/>tribal auditors acting under agreements under the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 <E T="03">et seq.</E> or other applicable agreements.</P> <P> <E T="03">Minimum royalty</E> means that minimum amount of annual royalty that the lessee must pay as specified in the lease or in applicable leasing regulations.</P> <P> <E T="03">Natural gas liquids (NGL's)</E> means those gas plant products consisting of ethane, propane, butane, or heavier liquid hydrocarbons.</P> <P> <E T="03">Net-back method</E> (or <E T="03">work-back method</E>) means a method for calculating market value of gas at the lease under which costs of transportation, processing, and manufacturing are deducted from the proceeds received for, or the value of, the gas, residue gas, or gas plant products, and any extracted, processed, or manufactured products, at the first point at which reasonable values for any such products may be determined by a sale under an arm's-length contract or comparison to other sales of such products.</P> <P> <E T="03">Net output</E> means the quantity of residue gas and each gas plant product that a processing plant produces.</P> <P> <E T="03">Net profit share</E> means the specified share of the net profit from production of oil and gas as provided in the agreement.</P> <P> <E T="03">Operating rights owner</E> (or <E T="03">working interest owner</E>) means any person who owns operating rights in a lease subject to this subpart. A record title owner is the owner of operating rights under a lease except to the extent that the operating rights or a portion thereof have been transferred from record title (see BLM regulations at 43 CFR 3100.0-5(d)).</P> <P> <E T="03">Person</E> means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).</P> <P> <E T="03">Point of royalty measurement</E> means the same as facility measurement point.</P> <P> <E T="03">Processing</E> means any process designed to remove elements or compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes which normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, desulphurization (or “sweetening”), and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing.</P> <P> <E T="03">Residue</E> gas means that hydrocarbon gas consisting principally of methane resulting from processing gas.</P> <P> <E T="03">Selling arrangement</E> means the individual contractual arrangements under which sales or dispositions of gas, residue gas and gas plant products are made. Selling arrangements are described by illustration in the “MMS Royalty Management Program Oil and Gas Payor Handbook.”</P> <P> <E T="03">Spot sales agreement</E> means a contract wherein a seller agrees to sell to a buyer a specified amount of unprocessed gas, residue gas, or gas plant products at a specified price over a fixed period, usually of short duration. It also does not normally require a cancellation notice to terminate, and does not contain an obligation, or imply an intent, to continue in subsequent periods.</P> <P> <E T="03">Takes</E> means when the operating rights owner sells or removes production from, or allocated to, the lease, or when such sale or removal occurs for the benefit of an operating rights owner.</P> <P> <E T="03">Work-back method</E> means the same as net-back method.</P> </SECTION> <SECTION> <SECTNO>§ 206.172</SECTNO> <SUBJECT>How do I value gas produced from leases in an index zone?</SUBJECT> <P>(a) <E T="03">What leases this section applies to.</E> This section explains how lessees must value, for royalty purposes, gas produced from Indian leases located in an index zone. For other leases, value must be determined under § 206.174.</P> <P>(1) You must use the valuation provision of this section if your lease is in an index zone and meets one of the following two requirements:</P> <P>(i) Has a major portion provision;</P> <P>(ii) Does not have a major portion provision, but provides for the Secretary to determine the value of production.</P> <P>(2) This section does not apply to carbon dioxide, nitrogen, or other non-hydrocarbon components of the gas stream. However, if they are recovered and sold separately from the gas <PRTPAGE P="105"/>stream, you must determine the value of these products under § 206.174.</P> <P>(b) <E T="03">Valuing residue gas and gas before processing.</E> (1) Except as provided in paragraphs (e), (f), and (g) of this section, this paragraph (b) explains how you must value the following four types of gas:</P> <P>(i) Gas production before processing;</P> <P>(ii) Gas production that you certify on Form MMS-4410, Certification for Not Performing Accounting for Comparison (Dual Accounting), is not processed before it flows into a pipeline with an index but which may be processed later;</P> <P>(iii) Residue gas after processing; and</P> <P>(iv) Gas that is never processed.</P> <P>(2) The value of gas production that is not sold under an arm's-length dedicated contract is the index-based value determined under paragraph (d) of this section unless the gas was subject to a previous contract which was part of a gas contract settlement. If the previous contract was subject to a gas contract settlement and if the royalty-bearing contract settlement proceeds per MMBtu added to the 80 percent of the safety net prices calculated at § 206.172(e)(4)(i) exceeds the index-based value that applies to the gas under this section (including any adjustments required under § 206.176), then the value of the gas is the higher of the value determined under this section (including any adjustments required under § 206.176) or § 206.174.</P> <P>(3) The value of gas production that is sold under an arm's-length dedicated contract is the higher of the index-based value under paragraph (d) of this section or the value of that production determined under § 206.174(b).</P> <P>(c) <E T="03">Valuing gas that is processed before it flows into a pipeline with an index.</E> Except as provided in paragraphs (e), (f), and (g) of this section, this paragraph (c) explains how you must value gas that is processed before it flows into a pipeline with an index. You must value this gas production based on the higher of the following two values:</P> <P>(1) The value of the gas before processing determined under paragraph (b) of this section.</P> <P>(2) The value of the gas after processing, which is either the alternative dual accounting value under § 206.173 or the sum of the following three values:</P> <P>(i) The value of the residue gas determined under paragraph (b)(2) or (3) of this section, as applicable;</P> <P>(ii) The value of the gas plant products determined under § 206.174, less any applicable processing and/or transportation allowances determined under this subpart; and</P> <P>(iii) The value of any drip condensate associated with the processed gas determined under subpart B of this part.</P> <P>(d) <E T="03">Determining the index-based value for gas production.</E> (1) To determine the index-based value per MMBtu for production from a lease in an index zone, you must use the following procedures:</P> <P>(i) For each MMS-approved publication, calculate the average of the highest reported prices for all index-pricing points in the index zone, except for any prices excluded under paragraph (d)(6) of this section;</P> <P>(ii) Sum the averages calculated in paragraph (d)(1)(i) of this section and divide by the number of publications; and</P> <P>(iii) Reduce the number calculated under paragraph (d)(1)(ii) of this section by 10 percent, but not by less than 10 cents per MMBtu or more than 30 cents per MMBtu. The result is the index-based value per MMBtu for production from all leases in that index zone.</P> <P>(2) MMS will publish in the <E T="04">Federal Register</E> the index zones that are eligible for the index-based valuation method under this paragraph. MMS will monitor the market activity in the index zones and, if necessary, hold a technical conference to add or modify a particular index zone. Any change to the index zones will be published in the <E T="04">Federal Register.</E> MMS will consider the following five factors and conditions in determining eligible index zones:</P> <P>(i) Areas for which MMS-approved publications establish index prices that accurately reflect the value of production in the field or area where the production occurs;</P> <P>(ii) Common markets served;</P> <P>(iii) Common pipeline systems;</P> <P>(iv) Simplification; and<PRTPAGE P="106"/> </P> <P>(v) Easy identification in MMS's systems, such as counties or Indian reservations.</P> <P>(3) If market conditions change so that an index-based method for determining value is no longer appropriate for an index zone, MMS will hold a technical conference to consider disqualification of an index zone. MMS will publish notice in the <E T="04">Federal Register</E> if an index zone is disqualified. If an index zone is disqualified, then production from leases in that index zone cannot be valued under this paragraph.</P> <P>(4) MMS periodically will publish in the <E T="04">Federal Register</E> a list of acceptable publications based on certain criteria, including, but not limited to the following five criteria:</P> <P>(i) Publications buyers and sellers frequently use;</P> <P>(ii) Publications frequently referenced in purchase or sales contracts;</P> <P>(iii) Publications that use adequate survey techniques, including the gathering of information from a substantial number of sales;</P> <P>(iv) Publications that publish the range of reported prices they use to calculate their index; and</P> <P>(v) Publications independent from DOI, lessors, and lessees.</P> <P>(5) Any publication may petition MMS to be added to the list of acceptable publications.</P> <P>(6) MMS may exclude an individual index price for an index zone in an MMS-approved publication if MMS determines that the index price does not accurately reflect the value of production in that index zone. MMS will publish a list of excluded indices in the <E T="04">Federal Register</E>.</P> <P>(7) MMS will reference which tables in the publications you must use for determining the associated index prices.</P> <P>(8) The index-based values determined under this paragraph are not subject to deductions for transportation or processing allowances determined under §§ 206.177, 206.178, 206.179, and 206.180.</P> <P>(e) <E T="03">Determining the minimum value for royalty purposes of gas sold beyond the first index pricing point.</E> (1) Notwithstanding any other provision of this section, the value for royalty purposes of gas production from an Indian lease that is sold beyond the first index pricing point through which it flows cannot be less than the value determined under this paragraph (e).</P> <P>(2) By June 30 following any calendar year, you must calculate for each month of that calendar year your safety net price per MMBtu using the procedures in paragraph (e)(3) of this section. You must calculate a safety net price for each month and for each index zone where you have an Indian lease for which you report and pay royalties.</P> <P>(3) Your safety net price (S) for an index zone is the volume-weighted average contract price per delivered MMBtu under your or your affiliate's arm's-length contracts for the disposition of residue gas or unprocessed gas produced from your Indian leases in that index zone as computed under this paragraph (e)(3).</P> <P>(i) Include in your calculation only sales under those contracts that establish a delivery point beyond the first index pricing point through which the gas flows, and that include any gas produced from or allocable to one or more of your Indian leases in that index zone, even if the contract also includes gas produced from Federal, State, or fee properties. Include in your volume-weighted average calculation those volumes that are allocable to your Indian leases in that index zone.</P> <P>(ii) Do not reduce the contract price for any transportation costs incurred to deliver the gas to the purchaser.</P> <P>(iii) For purposes of this paragraph (e), the contract price will not include the following amounts:</P> <P>(A) Any amounts you receive in compromise or settlement of a predecessor contract for that gas;</P> <P>(B) Deductions for you or any other person to put gas production into marketable condition or to market the gas; and</P> <P>(C) Any amounts related to marketable securities associated with the sales contract.</P> <P>(4) Next, you must determine for each month the safety net differential (SND). You must perform this calculation separately for each index zone.</P> <P>(i) For each index zone, the safety net differential is equal to: SND = [(0.80 × S) − (1.25 × I)] where (I) is the index-<PRTPAGE P="107"/>based value determined under 30 CFR 206.172(d).</P> <P>(ii) If the safety net differential is positive you owe additional royalties.</P> <P>(5)(i) To calculate the additional royalties you owe, make the following calculation for each of your Indian leases in that index zone that produced gas that was sold beyond the first index-pricing point through which the gas flowed and that was used in the calculation in paragraph (e)(3) of this section: </P> <EXTRACT> <P>Lease royalties owed = SND × V × R, where R = the lease royalty rate and V = the volume allocable to the lease which produced gas that was sold beyond the first index pricing point.</P> </EXTRACT> <P>(ii) If gas produced from any of your Indian leases is commingled or pooled with gas produced from non-Indian properties, and if any of the combined gas is sold at a delivery point beyond the first index pricing point through which the gas flows, then the volume allocable to each Indian lease for which gas was sold beyond the first index pricing point in the calculation under paragraph (e)(5)(i) of this section is the volume produced from the lease multiplied by the proportion that the total volume of gas sold beyond the first index pricing point bears to the total volume of gas commingled or pooled from all properties.</P> <P>(iii) Add the numbers calculated for each lease under paragraph (e)(5)(i) of this section. The total is the additional royalty you owe.</P> <P>(6) You have the following responsibilities to comply with the minimum value for royalty purposes:</P> <P>(i) You must report the safety net price for each index zone to MMS on Form MMS-4411, Safety Net Report, no later than June 30 following each calendar year;</P> <P>(ii) You must pay and report on Form MMS-2014 additional royalties due no later than June 30 following each calendar year; and</P> <P>(iii) MMS may order you to amend your safety net price within one year from the date your Form MMS-4411 is due or is filed, whichever is later. If MMS does not order any amendments within that one-year period, your safety net price calculation is final.</P> <P>(f) <E T="03">Excluding some or all tribal leases from valuation under this section.</E> (1) An Indian tribe may ask MMS to exclude some or all of its leases from valuation under this section. MMS will consult with BIA regarding the request.</P> <P>(i) If MMS approves the request for your lease, you must value your production under § 206.174 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the <E T="04">Federal Register</E>.</P> <P>(ii) If an Indian tribe requests exclusion from an index zone for less than all of its leases, MMS will approve the request only if the excluded leases may be segregated into one or more groups based on separate fields within the reservation.</P> <P>(2) An Indian tribe may ask MMS to terminate exclusion of its leases from valuation under this section. MMS will consult with BIA regarding the request.</P> <P>(i) If MMS approves the request, you must value your production under § 206.172 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the <E T="04">Federal Register</E>.</P> <P>(ii) Termination of an exclusion under paragraph (f)(2)(i) of this section cannot take effect earlier than 1 year after the first day of the production month that the exclusion was effective.</P> <P>(3) The Indian tribe's request to MMS under either paragraph (f)(1) or (2) of this section must be in the form of a tribal resolution.</P> <P>(g) <E T="03">Excluding Indian allotted leases from valuation under this section.</E> (1)(i) MMS may exclude any Indian allotted leases from valuation under this section. MMS will consult with BIA regarding the exclusion.</P> <P>(ii) If MMS excludes your lease, you must value your production under § 206.174 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the <E T="04">Federal Register</E>.</P> <P>(iii) If MMS excludes any Indian allotted leases under this paragraph (g)(1), it will exclude all Indian allotted leases in the same field.<PRTPAGE P="108"/> </P> <P>(2)(i) MMS may terminate the exclusion of any Indian allotted leases from valuation under this section. MMS will consult with BIA regarding the termination.</P> <P>(ii) If MMS terminates the exclusion, you must value your production under § 206.172 beginning with production on the first day of the second month following the date MMS publishes notice of its decision in the <E T="04">Federal Register</E>.</P> </SECTION> <SECTION> <SECTNO>§ 206.173</SECTNO> <SUBJECT>How do I calculate the alternative methodology for dual accounting?</SUBJECT> <P>(a) <E T="03">Electing a dual accounting method.</E> (1) If you are required to perform the accounting for comparison (dual accounting) under § 206.176, you have two choices. You may elect to perform the dual accounting calculation according to either § 206.176(a) (called actual dual accounting), or paragraph (b) of this section (called the alternative methodology for dual accounting).</P> <P>(2) You must make a separate election to use the alternative methodology for dual accounting for your Indian leases in each MMS-designated area. Your election for a designated area must apply to all of your Indian leases in that area.</P> <P>(i) MMS will publish in the <E T="04">Federal Register</E> a list of the lease prefixes that will be associated with each designated area for purposes of this section. The MMS-designated areas are as follows:</P> <P>(A) Alabama-Coushatta;</P> <P>(B) Blackfeet Reservation;</P> <P>(C) Crow Reservation;</P> <P>(D) Fort Belknap Reservation;</P> <P>(E) Fort Berthold Reservation;</P> <P>(F) Fort Peck Reservation;</P> <P>(G) Jicarilla Apache Reservation;</P> <P>(H) MMS-designated groups of counties in the State of Oklahoma;</P> <P>(I) Navajo Reservation;</P> <P>(J) Northern Cheyenne Reservation;</P> <P>(K) Rocky Boys Reservation;</P> <P>(L) Southern Ute Reservation;</P> <P>(M) Turtle Mountain Reservation;</P> <P>(N) Ute Mountain Ute Reservation;</P> <P>(O) Uintah and Ouray Reservation;</P> <P>(P) Wind River Reservation; and</P> <P>(Q) Any other area that MMS designates. MMS will publish a new area designation in the <E T="04">Federal Register</E>.</P> <P>(ii) You may elect to begin using the alternative methodology for dual accounting at the beginning of any month. The first election to use the alternative methodology will be effective from the time of election through the end of the following calendar year. Thereafter, each election to use the alternative methodology must remain in effect for 2 calendar years. You may return to the actual dual accounting method only at the beginning of the next election period or with the written approval of MMS and the tribal lessor for tribal leases, and MMS for Indian allottee leases in the designated area.</P> <P>(iii) When you elect to use the alternative methodology for a designated area, you must also use the alternative methodology for any new wells commenced and any new leases acquired in the designated area during the term of the election.</P> <P>(b) <E T="03">Calculating value using the alternative methodology for dual accounting.</E> (1) The alternative methodology adjusts the value of gas before processing determined under either § 206.172 or § 206.174 to provide the value of the gas after processing. You must use the value of the gas after processing for royalty payment purposes. The amount of the increase depends on your relationship with the owner(s) of the plant where the gas is processed. If you have no direct or indirect ownership interest in the processing plant, then the increase is lower, as provided in the table in paragraph (b)(2)(ii) of this section. If you have a direct or indirect ownership interest in the plant where the gas is processed, the increase is higher, as provided in paragraph (b)(2)(ii) of this section.</P> <P>(2) To calculate the value of the gas after processing using the alternative methodology for dual accounting, you must apply the increase to the value before processing, determined in either § 206.172 or § 206.174, as follows:</P> <P>(i) Value of gas after processing = (value determined under either § 206.172 or § 206.174, as applicable) × (1 + increment for dual accounting); and</P> <P>(ii) In this equation, the increment for dual accounting is the number you <PRTPAGE P="109"/>take from the applicable Btu range, determined under paragraph (b)(3) of this section, in the following table:</P> <GPOTABLE CDEF="s50,10,10" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1">BTU range</CHED> <CHED H="1">Increment if Lessee has no ownership interest in plant</CHED> <CHED H="1">Increment if lessee has an ownership interest in plant</CHED> </BOXHD> <ROW> <ENT I="01">1001 to 1050</ENT> <ENT>.0275</ENT> <ENT>.0375</ENT> </ROW> <ROW> <ENT I="01">1051 to 1100</ENT> <ENT>.0400</ENT> <ENT>.0625</ENT> </ROW> <ROW> <ENT I="01">1101 to 1150</ENT> <ENT>.0425</ENT> <ENT>.0750</ENT> </ROW> <ROW> <ENT I="01">1151 to 1200</ENT> <ENT>.0700</ENT> <ENT>.1225</ENT> </ROW> <ROW> <ENT I="01">1201 to 1250</ENT> <ENT>.0975</ENT> <ENT>.1700</ENT> </ROW> <ROW> <ENT I="01">1251 to 1300</ENT> <ENT>.1175</ENT> <ENT>.2050</ENT> </ROW> <ROW> <ENT I="01">1301 to 1350</ENT> <ENT>.1400</ENT> <ENT>.2400</ENT> </ROW> <ROW> <ENT I="01">1351 to 1400</ENT> <ENT>.1450</ENT> <ENT>.2500</ENT> </ROW> <ROW> <ENT I="01">1401 to 1450</ENT> <ENT>.1500</ENT> <ENT>.2600</ENT> </ROW> <ROW> <ENT I="01">1451 to 1500</ENT> <ENT>.1550</ENT> <ENT>.2700</ENT> </ROW> <ROW> <ENT I="01">1501 to 1550</ENT> <ENT>.1600</ENT> <ENT>.2800</ENT> </ROW> <ROW> <ENT I="01">1551 to 1600</ENT> <ENT>.1650</ENT> <ENT>.2900</ENT> </ROW> <ROW> <ENT I="01">1601 to 1650</ENT> <ENT>.1850</ENT> <ENT>.3225</ENT> </ROW> <ROW> <ENT I="01">1651 to 1700</ENT> <ENT>.1950</ENT> <ENT>.3425</ENT> </ROW> <ROW> <ENT I="01">1701+</ENT> <ENT>.2000</ENT> <ENT>.3550</ENT> </ROW> </GPOTABLE> <P>(3) The applicable Btu for purposes of this section is the volume weighted-average Btu for the lease computed from measurements at the facility measurement point(s) for gas production from the lease.</P> <P>(4) If any of your gas from the lease is processed during a month, use the following two paragraphs to determine which amounts are subject to dual accounting and which dual accounting method you must use.</P> <P>(i) Weighted-average Btu content determined under paragraph (b)(3) of this section is greater than 1,000 Btu's per cubic foot (Btu/cf). All gas production from the lease is subject to dual accounting and you must use the alternative method for all that gas production if you elected to use the alternative method under this section.</P> <P>(ii) Weighted-average Btu content determined under paragraph (b)(3) of this section is less than or equal to 1,000 Btu/cf. Only the volumes of lease production measured at facility measurement points whose quality exceeds 1,000 Btu/cf are subject to dual accounting, and you may use the alternative methodology for these volumes. For gas measured at facility measurement points for these leases where the quality is equal to or less than 1,000 Btu/cf, you are not required to do dual accounting.</P> </SECTION> <SECTION> <SECTNO>§ 206.174</SECTNO> <SUBJECT>How do I value gas production when an index-based method cannot be used?</SUBJECT> <P>(a) <E T="03">Situations in which an index-based method cannot be used.</E> (1) Gas production must be valued under this section in the following situations.</P> <P>(i) Your lease is not in an index zone (or MMS has excluded your lease from an index zone).</P> <P>(ii) If your lease is in an index zone and you sell your gas under an arm's-length dedicated contract, then the value of your gas is the higher of the value received under the dedicated contract determined under § 206.174(b) or the value under § 206.172.</P> <P>(iii) Also use this section to value any other gas production that cannot be valued under § 206.172, as well as gas plant products, and to value components of the gas stream that have no Btu value (for example, carbon dioxide, nitrogen, etc.).</P> <P>(2) The value for royalty purposes of gas production subject to this subpart is the value of gas determined under this section less applicable allowances determined under this subpart.</P> <P>(3) You must determine the value of gas production that is processed and is subject to accounting for comparison using the procedure in § 206.176.</P> <P>(4) This paragraph applies if your lease has a major portion provision. It also applies if your lease does not have a major portion provision but the lease provides for the Secretary to determine value.</P> <P>(i) The value of production you must initially report and pay is the value determined in accordance with the other paragraphs of this section.</P> <P>(ii) MMS will determine the major portion value and notify you in the <E T="04">Federal Register</E> of that value. The value of production for royalty purposes for your lease is the higher of either the value determined under this section which you initially used to report and pay royalties, or the major portion value calculated under this paragraph (a)(4). If the major portion value is higher, you must submit an amended Form MMS-2014 to MMS by the due date specified in the written notice from MMS of the major portion value. Late-payment interest under 30 CFR 218.54 on any underpayment will <PRTPAGE P="110"/>not begin to accrue until the date the amended Form MMS-2014 is due to MMS.</P> <P>(iii) Except as provided in paragraph (a)(4)(iv) of this section, MMS will calculate the major portion value for each designated area (which are the same designated areas as under § 206.173) using values reported for unprocessed gas and residue gas on Form MMS-2014 for gas produced from leases on that Indian reservation or other designated area. MMS will array the reported prices from highest to lowest price. The major portion value is that price at which 25 percent (by volume) of the gas (starting from the highest) is sold. MMS cannot unilaterally change the major portion value after you are notified in writing of what that value is for your leases.</P> <P>(iv) MMS may calculate the major portion value using different data than the data described in paragraph (a)(4)(iii) of this section or data to augment the data described in paragraph (a)(4)(iii) of this section. This may include price data reported to the State tax authority or price data from leases MMS has reviewed in the designated area. MMS may use this alternate or the augmented data source beginning with production on the first day of the month following the date MMS publishes notice in the <E T="04">Federal Register</E> that it is calculating the major portion using a method in this paragraph (a)(4)(iv) of this section.</P> <P>(b) <E T="03">Arm's-length contracts.</E> (1) The value of gas, residue gas, or any gas plant product you sell under an arm's-length contract is the gross proceeds accruing to you or your affiliate, except as provided in paragraphs (b)(1)(ii)-(iv) of this section.</P> <P>(i) You have the burden of demonstrating that your contract is arm's-length.</P> <P>(ii) In conducting reviews and audits for gas valued based upon gross proceeds under this paragraph, MMS will examine whether or not your contract reflects the total consideration actually transferred either directly or indirectly from the buyer to you or your affiliate for the gas, residue gas, or gas plant product. If the contract does not reflect the total consideration, then MMS may require that the gas, residue gas, or gas plant product sold under that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to you or your affiliate, including the additional consideration.</P> <P>(iii) If MMS determines for gas valued under this paragraph that the gross proceeds accruing to you or your affiliate under an arm's-length contract do not reflect the value of the gas, residue gas, or gas plant products because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the gas, residue gas, or gas plant product be valued under paragraphs (c)(2) or (3) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your value.</P> <P>(iv) This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all over-delivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the over-delivery tolerances even if those volumes are subject to a lower price specified in the transportation contract. However, if MMS determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessees must value all over-delivered volumes under paragraph (c)(2) or (3) of this section.</P> <P>(2) MMS may require you to certify that your arm's-length contract provisions include all of the consideration the buyer pays, either directly or indirectly, for the gas, residue gas, or gas plant product.</P> <P>(c) <E T="03">Non-arm's-length contracts.</E> If your gas, residue gas, or any gas plant product is not sold under an arm's-length contract, then you must value the production using the first applicable method of the following three methods:<PRTPAGE P="111"/> </P> <P>(1) The gross proceeds accruing to you under your non-arm's-length contract sale (or other disposition other than by an arm's-length contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm's-length contracts for purchases, sales, or other dispositions of like-quality gas in the same field (or, if necessary to obtain a reasonable sample, from the same area). For residue gas or gas plant products, the comparable arm's-length contracts must be for gas from the same processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors will be considered: price, time of execution, duration, market or markets served, terms, quality of gas, residue gas, or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the gas, residue gas, or gas plant products.</P> <P>(2) A value determined by consideration of other information relevant in valuing like-quality gas, residue gas, or gas plant products, including gross proceeds under arm's-length contracts for like-quality gas in the same field or nearby fields or areas, or for residue gas or gas plant products from the same gas plant or other nearby processing plants. Other factors to consider include prices received in spot sales of gas, residue gas or gas plant products, other reliable public sources of price or market information, and other information as to the particular lease operation or the salability of such gas, residue gas, or gas plant products.</P> <P>(3) A net-back method or any other reasonable method to determine value.</P> <P>(d) <E T="03">Supporting data.</E> If you determine the value of production under paragraph (c) of this section, you must retain all data relevant to the determination of royalty value.</P> <P>(1) Such data will be subject to review and audit, and MMS will direct you to use a different value if we determine upon review or audit that the value you reported is inconsistent with the requirements of these regulations.</P> <P>(2) You must make all such data available upon request to the authorized MMS or Indian representatives, to the Office of the Inspector General of the Department, or other authorized persons. This includes your arm's-length sales and volume data for like-quality gas, residue gas, and gas plant products that are sold, purchased, or otherwise obtained from the same processing plant or from nearby processing plants, or from the same or nearby field or area.</P> <P>(e) <E T="03">Improper values.</E> If MMS determines that you have not properly determined value, you must pay the difference, if any, between royalty payments made based upon the value you used and the royalty payments that are due based upon the value MMS established. You also must pay interest computed on that difference under 30 CFR 218.54. If you are entitled to a credit, MMS will provide instructions on how to take that credit.</P> <P>(f) <E T="03">Value guidance.</E> You may ask MMS for guidance in determining value. You may propose a valuation method to MMS. Submit all available data related to your proposal and any additional information MMS deems necessary. MMS will promptly review your proposal and provide you with a non-binding determination of the guidance you request.</P> <P>(g) <E T="03">Minimum value of production.</E> (1) For gas, residue gas, and gas plant products valued under this section, under no circumstances may the value of production for royalty purposes be less than the gross proceeds accruing to the lessee (including its affiliates) for gas, residue gas and/or any gas plant products, less applicable transportation allowances and processing allowances determined under this subpart.</P> <P>(2) For gas plant products valued under this section and not valued under § 206.173, the alternative methodology for dual accounting, the minimum value of production for each gas plant product is as follows:</P> <P>(i) Leases in certain States and areas have specific minimum values.</P> <P>(A) For production from leases in Colorado in the San Juan Basin, New Mexico, and Texas, the monthly average minimum price reported in commercial price bulletins for the gas plant product at Mont Belvieu, Texas, minus 8.0 cents per gallon.<PRTPAGE P="112"/> </P> <P>(B) For production in Arizona, in Colorado outside the San Juan Basin, Minnesota, Montana, North Dakota, Oklahoma, South Dakota, Utah, and Wyoming, the monthly average minimum price reported in commercial price bulletins for the gas plant product at Conway, Kansas, minus 7.0 cents per gallon;</P> <P>(ii) You may use any commercial price bulletin, but you must use the same bulletin for all of the calendar year. If the commercial price bulletin you are using stops publication, you may use a different commercial price bulletin for the remaining part of the calendar year; and (iii) If you use a commercial price bulletin that is published monthly, the monthly average minimum price is the bulletin's minimum price. If you use a commercial price bulletin that is published weekly, the monthly average minimum price is the arithmetic average of the bulletin's weekly minimum prices. If you use a commercial price bulletin that is published daily, the monthly average minimum price is the arithmetic average of the bulletin's minimum prices for each Wednesday in the month.</P> <P>(h) <E T="03">Marketable condition/Marketing.</E> You are required to place gas, residue gas, and gas plant products in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Indian lessor. When your gross proceeds establish the value under this section, that value must be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services to place the gas, residue gas, or gas plant products in marketable condition or to market the gas, the cost of which ordinarily is your responsibility.</P> <P>(i) <E T="03">Highest obtainable price or benefit.</E> For gas, residue gas, and gas plant products valued under this section, value must be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if you fail to take proper or timely action to receive prices or benefits to which you are entitled, you must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments must be in writing and signed by all parties to an arm's-length contract. If you make timely application for a price increase or benefit allowed under your contract but the purchaser refuses, and you take reasonable measures, which are documented, to force purchaser compliance, you will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph is not intended to permit you to avoid your royalty payment obligation in situations where your purchaser fails to pay, in whole or in part, or timely, for a quantity of gas, residue gas, or gas plant product.</P> <P>(j) <E T="03">Non-binding MMS reviews.</E> Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in an MMS redetermination of value under this section will be considered final or binding against the Federal Government or its beneficiaries until the audit period is formally closed.</P> <P>(k) <E T="03">Confidential information.</E> Certain information submitted to MMS to support valuation proposals, including transportation allowances and processing allowances, may be exempted from disclosure under the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable laws and regulations. All requests for information about determinations made under this subpart must be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.</P> <CITA>[64 FR 43515, Aug. 10, 1999, as amended at 65 FR 62614, Oct. 19, 2000]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.175</SECTNO> <SUBJECT>How do I determine quantities and qualities of production for computing royalties?</SUBJECT> <P>(a) For unprocessed gas, you must pay royalties on the quantity and quality at the facility measurement point BLM either allowed or approved.</P> <P>(b) For residue gas and gas plant products, you must pay royalties on your share of the monthly net output <PRTPAGE P="113"/>of the plant even though residue gas and/or gas plant products may be in temporary storage.</P> <P>(c) If you have no ownership interest in the processing plant and you do not operate the plant, you may use the contract volume allocation to determine your share of plant products.</P> <P>(d) If you have an ownership interest in the plant or if you operate it, use the following procedure to determine the quantity of the residue gas and gas plant products attributable to you for royalty payment purposes:</P> <P>(1) When the net output of the processing plant is derived from gas obtained from only one lease, the quantity of the residue gas and gas plant products on which you must pay royalty is the net output of the plant.</P> <P>(2) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to each lease must be in the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases.</P> <P>(3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of non-uniform content, the volumes of residue gas and gas plant products allocable to each lease are based on theoretical volumes of residue gas and gas plant products measured in the lease gas stream. You must calculate the portion of net plant output of residue gas and gas plant products attributable to each lease as follows:</P> <P>(i) First, compute the theoretical volumes of residue gas and of gas plant products attributable to the lease by multiplying the lease volume of the gas stream by the tested residue gas content (mole percentage) or gas plant product (GPM) content of the gas stream;</P> <P>(ii) Second, calculate the theoretical volumes of residue gas and of gas plant products delivered from all leases by summing the theoretical volumes of residue gas and of gas plant products delivered from each lease; and</P> <P>(iii) Third, calculate the theoretical quantities of net plant output of residue gas and of gas plant products attributable to each lease by multiplying the net plant output of residue gas, or gas plant products, by the ratio in which the theoretical volumes of residue gas, or gas plant products, is the numerator and the theoretical volume of residue gas, or gas plant products, delivered from all leases is the denominator.</P> <P>(4) You may request MMS approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If MMS approves a different method, it will be applicable to all gas production from your Indian leases that is processed in the same plant.</P> <P>(e) You may not take any deductions from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas incurred prior to the facility measurement point will not be subject to royalty if BLM determines that the loss was unavoidable.</P> </SECTION> <SECTION> <SECTNO>§ 206.176</SECTNO> <SUBJECT>How do I perform accounting for comparison?</SUBJECT> <P>(a) This section applies if the gas produced from your Indian lease is processed and that Indian lease requires accounting for comparison (also referred to as actual dual accounting). Except as provided in paragraphs (b) and (c) of this section, the actual dual accounting value, for royalty purposes, is the greater of the following two values:</P> <P>(1) The combined value of the following products:</P> <P>(i) The residue gas and gas plant products resulting from processing the gas determined under either § 206.172 or § 206.174, less any applicable allowances; and</P> <P>(ii) Any drip condensate associated with the processed gas recovered downstream of the point of royalty settlement without resorting to processing determined under § 206.52, less applicable allowances.</P> <P>(2) The value of the gas prior to processing determined under either § 206.172 or § 206.174, including any applicable allowances.</P> <P>(b) If you are required to account for comparison, you may elect to use the alternative dual accounting methodology provided for in § 206.173 instead of <PRTPAGE P="114"/>the provisions in paragraph (a) of this section.</P> <P>(c) Accounting for comparison is not required for gas if no gas from the lease is processed until after the gas flows into a pipeline with an index located in an index zone or into a mainline pipeline not in an index zone. If you do not perform dual accounting, you must certify to MMS that gas flows into such a pipeline before it is processed.</P> <P>(d) Except as provided in paragraph (e) of this section, if you value any gas production from a lease for a month using the dual accounting provisions of this section or the alternative dual accounting methodology of § 206.173, then the value of that gas is the minimum value for any other gas production from that lease for that month flowing through the same facility measurement point.</P> <P>(e) If the weighted-average Btu quality for your lease is less than 1,000 Btu's per cubic foot, see § 206.173(b)(4)(ii) to determine if you must perform a dual accounting calculation.</P> </SECTION> <SUBJGRP> <HD SOURCE="HED">Transportation Allowances</HD> <SECTION> <SECTNO>§ 206.177</SECTNO> <SUBJECT>What general requirements regarding transportation allowances apply to me?</SUBJECT> <P>(a) When you value gas under § 206.174 at a point off the lease, unit, or communitized area (for example, sales point or point of value determination), you may deduct from value a transportation allowance to reflect the value, for royalty purposes, at the lease, unit, or communitized area. The allowance is based on the reasonable actual costs you incurred to transport unprocessed gas, residue gas, or gas plant products from a lease to a point off the lease, unit, or communitized area. This would include, if appropriate, transportation from the lease to a gas processing plant off the lease, unit, or communitized area and from the plant to a point away from the plant. You may not deduct any allowance for gathering costs.</P> <P>(b) You must allocate transportation costs among all products you produce and transport as provided in § 206.178.</P> <P>(c)(1) Except as provided in paragraphs (c)(2) and (3) of this section, your transportation allowance deduction for each selling arrangement may not exceed 50 percent of the value of the unprocessed gas, residue gas, or gas plant product. For purposes of this section, natural gas liquids are considered one product.</P> <P>(2) If you ask MMS, MMS may approve a transportation allowance deduction in excess of the limitations in paragraph (c)(1) of this section. To receive this approval, you must demonstrate that the transportation costs incurred in excess of the limitations in paragraph (c)(1) of this section were reasonable, actual, and necessary. Under no circumstances may an allowance reduce the value for royalty purposes under any selling arrangement to zero.</P> <P>(3) Your application for exception (using Form MMS-4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for MMS to make a determination.</P> <P>(d) If MMS conducts a review or audit and determines that you have improperly determined a transportation allowance authorized by this subpart, then you will be required to pay any additional royalties, plus interest determined in accordance with 30 CFR 218.54. Alternatively, you may be entitled to a credit, but you will not receive any interest on your overpayment.</P> </SECTION> <SECTION> <SECTNO>§ 206.178</SECTNO> <SUBJECT>How do I determine a transportation allowance?</SUBJECT> <P>(a) <E T="03">Determining a transportation allowance under an arm's-length contract.</E> (1) This paragraph explains how to determine your allowance if you have an arm's-length transportation contract.</P> <P>(i) If you have an arm's-length contract for transportation of your production, the transportation allowance is the reasonable, actual costs you incur for transporting the unprocessed gas, residue gas and/or gas plant products under that contract. Paragraphs (a)(1)(ii) and (iii) of this section provide a limited exception. You have the burden of demonstrating that your contract is arm's-length. Your allowances also are subject to paragraph (e) of this section. You are required to submit to MMS a copy of your arm's-length transportation contract(s) and all subsequent amendments to the contract(s) <PRTPAGE P="115"/>within 2 months of the date MMS receives your report which claims the allowance on the Form MMS-2014.</P> <P>(ii) When either MMS or a tribe conducts reviews and audits, they will examine whether or not the contract reflects more than the consideration actually transferred either directly or indirectly from you to the transporter of the transportation. If the contract reflects more than the total consideration, then MMS may require that the transportation allowance be determined under paragraph (b) of this section.</P> <P>(iii) If MMS determines that the consideration paid under an arm's-length transportation contract does not reflect the value of the transportation because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the transportation allowance be determined under paragraph (b) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your transportation costs.</P> <P>(2) This paragraph explains how to allocate the costs to each product if your arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract.</P> <P>(i) If your arm's-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract, the total transportation costs must be allocated in a consistent and equitable manner to each of the products transported. To make this allocation, use the same proportion as the ratio that the volume of each product (excluding waste products which have no value) bears to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, you cannot take an allowance for the costs of transporting lease production that is not royalty bearing without MMS approval, or without lessor approval on tribal leases.</P> <P>(ii) As an alternative to paragraph (a)(2)(i) of this section, you may propose to MMS a cost allocation method based on the values of the products transported. MMS will approve the method if we determine that it meets one of the two following requirements:</P> <P>(A) The methodology in paragraph (a)(2)(i) of this section cannot be applied; and</P> <P>(B) Your proposal is more reasonable than the methodology in paragraph (a)(2)(i) of this section.</P> <P>(3) This paragraph explains how to allocate costs to each product if your arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract.</P> <P>(i) If your arm's-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract, you must propose an allocation procedure to MMS. You may use the transportation allowance determined in accordance with your proposed allocation procedure until MMS decides whether to accept your cost allocation.</P> <P>(ii) You are required to submit all relevant data to support your allocation proposal. MMS will then determine the gas transportation allowance based upon your proposal and any additional information MMS deems necessary.</P> <P>(4) If your payments for transportation under an arm's-length contract are not based on a dollar per unit price, you must convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.</P> <P>(5) Where an arm's-length sales contract price includes a reduction for a transportation factor, MMS will not consider the transportation factor to be a transportation allowance. You may use the transportation factor to determine your gross proceeds for the sale of the product. However, the transportation factor may not exceed 50 percent of the base price of the product without MMS approval.</P> <P>(b) <E T="03">Determining a transportation allowance under a non-arm's-length or no contract.</E> (1) This paragraph explains how to determine your allowance if you <PRTPAGE P="116"/>have a non-arm's-length transportation contract or no contract.</P> <P>(i) When you have a non-arm's-length transportation contract or no contract, including those situations where you perform transportation services for yourself, the transportation allowance is based upon your reasonable, allowable, actual costs for transportation as provided in this paragraph.</P> <P>(ii) All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and adjustment. You must submit the actual cost information to support the allowance to MMS on Form MMS-4295, Gas Transportation Allowance Report, within 3 months after the end of the 12-month period to which the allowance applies. However, MMS may approve a longer time period. MMS will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may require you to modify your actual transportation allowance deduction.</P> <P>(2) This paragraph explains what actual transportation costs are allowable under a non-arm's-length contract or no contract situation. The transportation allowance for non-arm's-length or no-contract situations is based upon your actual costs for transportation during the reporting period. Allowable costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment (in accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transportation system.</P> <P>(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expense that you can document.</P> <P>(ii) Allowable maintenance expenses include maintenance of the transportation system, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that you can document.</P> <P>(iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(iv) You may use either depreciation with a return on undepreciated capital investment or a return on depreciable capital investment. After you have elected to use either method for a transportation system, you may not later elect to change to the other alternative without MMS approval.</P> <P>(A) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the transportation system services, or a unit of production method. Once you make an election, you may not change methods without MMS approval. A change in ownership of a transportation system will not alter the depreciation schedule that the original transporter/lessee established for purposes of the allowance calculation. With or without a change in ownership, a transportation system may be depreciated only once. Equipment may not be depreciated below a reasonable salvage value. To compute a return on undepreciated capital investment, you will multiply the undepreciated capital investment in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section.</P> <P>(B) To compute a return on depreciable capital investment, you will multiply the initial capital investment in the transportation system by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance will be provided for depreciation. This alternative will apply only to transportation facilities first placed in service after March 1, 1988.</P> <P>(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return <PRTPAGE P="117"/>is the monthly average rate as published in <E T="03">Standard and Poor's Bond Guide</E> for the first month of the reporting period for which the allowance is applicable and is effective during the reporting period. The rate must be redetermined at the beginning of each subsequent transportation allowance reporting period that is determined under paragraph (b)(4) of this section.</P> <P>(3) This paragraph explains how to allocate transportation costs to each product and transportation system.</P> <P>(i) The deduction for transportation costs must be determined based on your cost of transporting each product through each individual transportation system. If you transport more than one product in a gaseous phase, the allocation of costs to each of the products transported must be made in a consistent and equitable manner. The allocation should be in the same proportion that the volume of each product (excluding waste products that have no value) bears to the volume of all products in the gaseous phase (excluding waste products that have no value). Except as provided in this paragraph, you may not take an allowance for transporting a product that is not royalty bearing without MMS approval.</P> <P>(ii) As an alternative to the requirements of paragraph (b)(3)(i) of this section, you may propose to MMS a cost allocation method based on the values of the products transported. MMS will approve the method upon determining that it meets one of the two following requirements:</P> <P>(A) The methodology in paragraph (b)(3)(i) of this section cannot be applied; and</P> <P>(B) Your proposal is more reasonable than the method in paragraph (b)(3)(i) of this section.</P> <P>(4) Your transportation allowance under this paragraph (b) must be determined based upon a calendar year or other period if you and MMS agree to an alternative.</P> <P>(5) If you transport both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to MMS. You may use the transportation allowance determined in accordance with your proposed allocation procedure until MMS issues its determination on the acceptability of the cost allocation. You are required to submit all relevant data to support your proposal. MMS will then determine the transportation allowance based upon your proposal and any additional information MMS deems necessary.</P> <P>(c) <E T="03">Using the alternative transportation calculation when you have a non-arm's-length or no contract.</E> (1) As an alternative to computing your transportation allowance under paragraph (b) of this section, you may use as the transportation allowance 10 percent of your gross proceeds but not to exceed 30 cents per MMBtu.</P> <P>(2) Your election to use the alternative transportation allowance calculation in paragraph (c)(1) of this section must be made at the beginning of a month and must remain in effect for an entire calendar year. Your first election will remain in effect until the end of the succeeding calendar year, except for elections effective January 1 that will be effective only for that calendar year.</P> <P>(d) <E T="03">Reporting your transportation allowance.</E> (1) If MMS requests, you must submit all data used to determine your transportation allowance. The data must be provided within a reasonable period of time that MMS will determine.</P> <P>(2) You must report transportation allowances as a separate line item on Form MMS-2014. MMS may approve a different reporting procedure on allottee leases, and with lessor approval on tribal leases.</P> <P>(e) <E T="03">Adjusting incorrect allowances.</E> If for any month the transportation allowance you are entitled to is less than the amount you took on Form MMS-2014, you are required to report and pay additional royalties due, plus interest computed under 30 CFR 218.54 from the first day of the first month you deducted the improper transportation allowance until the date you pay the royalties due. If the transportation allowance you are entitled to is greater than the amount you took on Form MMS-2014 for any royalties during the reporting period, you are entitled to a credit. No interest will be paid on the overpayment.</P> <P>(f) <E T="03">Determining allowable costs for transportation allowances.</E> Lessees may <PRTPAGE P="118"/>include, but are not limited to, the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section:</P> <P>(1) <E T="03">Firm demand charges paid to pipelines.</E> You must limit the allowable costs for the firm demand charges to the applicable rate per MMBtu multiplied by the actual volumes transported. You may not include any losses incurred for previously purchased but unused firm capacity. You also may not include any gains associated with releasing firm capacity. If you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the Form MMS-2014. You must modify the Form MMS-2014 by the amount received or credited for the affected reporting period.</P> <P>(2) <E T="03">Gas supply realignment (GSR) costs.</E> The GSR costs result from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC orders in 18 CFR part 284.</P> <P>(3) <E T="03">Commodity charges.</E> The commodity charge allows the pipeline to recover the costs of providing service.</P> <P>(4) <E T="03">Wheeling costs.</E> Hub operators charge a wheeling cost for transporting gas from one pipeline to either the same or another pipeline through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines.</P> <P>(5) <E T="03">Gas Research Institute (GRI) fees.</E> The GRI conducts research, development, and commercialization programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers. GRI fees are allowable provided such fees are mandatory in FERC-approved tariffs.</P> <P>(6) <E T="03">Annual Charge Adjustment (ACA) fees.</E> FERC charges these fees to pipelines to pay for its operating expenses.</P> <P>(7) <E T="03">Payments (either volumetric or in value) for actual or theoretical losses.</E> This paragraph does not apply to non-arm's-length transportation arrangements.</P> <P>(8) <E T="03">Temporary storage services.</E> This includes short duration storage services offered by market centers or hubs (commonly referred to as “parking” or “banking”), or other temporary storage services provided by pipeline transporters, whether actual or provided as a matter of accounting. Temporary storage is limited to 30 days or less.</P> <P>(9) <E T="03">Supplemental costs for compression, dehydration, and treatment of gas.</E> MMS allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under § 206.174(h).</P> <P>(g) <E T="03">Determining nonallowable costs for transportation allowances.</E> Lessees may not include the following costs in determining the arm's-length transportation allowance under paragraph (a) of this section or the non-arm's-length transportation allowance under paragraph (b) of this section:</P> <P>(1) <E T="03">Fees or costs incurred for storage.</E> This includes storing production in a storage facility, whether on or off the lease, for more than 30 days.</P> <P>(2) <E T="03">Aggregater/marketer fees.</E> This includes fees you pay to another person (including your affiliates) to market your gas, including purchasing and reselling the gas, or finding or maintaining a market for the gas production.</P> <P>(3) <E T="03">Penalties you incur as shipper.</E> These penalties include, but are not limited to the following:</P> <P>(i) <E T="03">Over-delivery cash-out penalties.</E> This includes the difference between the price the pipeline pays you for over-delivered volumes outside the tolerances and the price you receive for over-delivered volumes within tolerances.</P> <P>(ii) <E T="03">Scheduling penalties.</E> This includes penalties you incur for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point.</P> <P>(iii) <E T="03">Imbalance penalties.</E> This includes penalties you incur (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point.</P> <P>(iv) <E T="03">Operational penalties.</E> This includes fees you incur for violation of <PRTPAGE P="119"/>the pipeline's curtailment or operational orders issued to protect the operational integrity of the pipeline.</P> <P>(4) <E T="03">Intra-hub transfer fees.</E> These are fees you pay to hub operators for administrative services (e.g., title transfer tracking) necessary to account for the sale of gas within a hub.</P> <P>(5) <E T="03">Other nonallowable costs.</E> Any cost you incur for services you are required to provide at no cost to the lessor.</P> <P>(h) <E T="03">Other transportation cost determinations.</E> You must follow the provisions of this section to determine transportation costs when establishing value using either a net-back valuation procedure or any other procedure that allows deduction of actual transportation costs.</P> </SECTION> </SUBJGRP> <SUBJGRP> <HD SOURCE="HED">Processing Allowances</HD> <SECTION> <SECTNO>§ 206.179</SECTNO> <SUBJECT>What general requirements regarding processing allowances apply to me?</SUBJECT> <P>(a) When you value any gas plant product under § 206.174, you may deduct from value the reasonable actual costs of processing.</P> <P>(b) You must allocate processing costs among the gas plant products. You must determine a separate processing allowance for each gas plant product and processing plant relationship. Natural gas liquids are considered as one product.</P> <P>(c) The processing allowance deduction based on an individual product may not exceed 66 2/3 percent of the value of each gas plant product determined under § 206.174. Before you calculate the 66 2/3 percent limit, you must first reduce the value for any transportation allowances related to post-processing transportation authorized under § 206.177.</P> <P>(d) Processing cost deductions will not be allowed for placing lease products in marketable condition. These costs include among others, dehydration, separation, compression upstream of the facility measurement point, or storage, even if those functions are performed off the lease or at a processing plant. Costs for the removal of acid gases, commonly referred to as sweetening, are not allowed unless the acid gases removed are further processed into a gas plant product. In such event, you will be eligible for a processing allowance determined under this subpart. However, MMS will not grant any processing allowance for processing lease production that is not royalty bearing.</P> <P>(e) You will be allowed a reasonable amount of residue gas royalty free for operation of the processing plant, but no allowance will be made for expenses incidental to marketing, except as provided in 30 CFR part 206. In those situations where a processing plant processes gas from more than one lease, only that proportionate share of your residue gas necessary for the operation of the processing plant will be allowed royalty free.</P> <P>(f) You do not owe royalty on residue gas, or any gas plant product resulting from processing gas, that is reinjected into a reservoir within the same lease, unit, or approved Federal agreement, until such time as those products are finally produced from the reservoir for sale or other disposition. This paragraph applies only when the reinjection is included in a BLM-approved plan of development or operations.</P> <P>(g) If MMS determines that you have determined an improper processing allowance authorized by this subpart, then you will be required to pay any additional royalties plus late payment interest determined under 30 CFR 218.54. Alternatively, you may be entitled to a credit, but you will not receive any interest on your overpayment.</P> </SECTION> <SECTION> <SECTNO>§ 206.180</SECTNO> <SUBJECT>How do I determine an actual processing allowance?</SUBJECT> <P>(a) <E T="03">Determining a processing allowance if you have an arms's-length processing contract.</E> (1) This paragraph explains how you determine an allowance under an arm's-length processing contract.</P> <P>(i) The processing allowance is the reasonable actual costs you incur to process the gas under that contract. Paragraphs (a)(1)(ii) and (iii) of this section provide a limited exception. You have the burden of demonstrating that your contract is arm's-length. You are required to submit to MMS a copy of your arm's-length contract(s) and all subsequent amendments to the contract(s) within 2 months of the date MMS receives your first report that deducts the allowance on the Form MMS-2014.<PRTPAGE P="120"/> </P> <P>(ii) When MMS conducts reviews and audits, we will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from you to the processor for the processing. If the contract reflects more than the total consideration, then MMS may require that the processing allowance be determined under paragraph (b) of this section.</P> <P>(iii) If MMS determines that the consideration paid under an arm's-length processing contract does not reflect the value of the processing because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of you and the lessor, then MMS will require that the processing allowance be determined under paragraph (b) of this section. In these circumstances, MMS will notify you and give you an opportunity to provide written information justifying your processing costs.</P> <P>(2) If your arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product can be determined from the contract, then the processing costs for each gas plant product must be determined in accordance with the contract. You may not take an allowance for the costs of processing lease production that is not royalty-bearing.</P> <P>(3) If your arm's-length processing contract includes more than one gas plant product and the processing costs attributable to each product cannot be determined from the contract, you must propose an allocation procedure to MMS. You may use your proposed allocation procedure until MMS issues its determination. You are required to submit all relevant data to support your proposal. MMS will then determine the processing allowance based upon your proposal and any additional information MMS deems necessary. You may not take a processing allowance for the costs of processing lease production that is not royalty-bearing.</P> <P>(4) If your payments for processing under an arm's-length contract are not based on a dollar per unit price, you must convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.</P> <P>(b) <E T="03">Determining a processing allowance if you have a non-arm's-length contract or no contract.</E> (1) This paragraph applies if you have a non-arm's-length processing contract or no contract, including those situations where you perform processing for yourself.</P> <P>(i) If you have a non-arm's-length contract or no contract, the processing allowance is based upon your reasonable actual costs of processing as provided in paragraph (b)(2) of this section.</P> <P>(ii) All processing allowances deducted under a non-arm's-length or no-contract situation are subject to monitoring, review, audit, and adjustment. You must submit the actual cost information to support the allowance to MMS on Form MMS-4109, Gas Processing Allowance Summary Report, within 3 months after the end of the 12-month period for which the allowance applies. MMS may approve a longer time period. MMS will monitor the allowance deduction to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may require you to modify your processing allowance.</P> <P>(2) The processing allowance for non-arm's-length or no-contract situations is based upon your actual costs for processing during the reporting period. Allowable costs include operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment (in accordance with paragraph (b)(2)(iv)(A) of this section), or a cost equal to the initial depreciable investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the processing plant.</P> <P>(i) Allowable operating expenses include operations supervision and engineering, operations labor, fuel, utilities, materials, ad valorem property taxes, rent, supplies, and any other directly allocable and attributable operating expense that the lessee can document.<PRTPAGE P="121"/> </P> <P>(ii) Allowable maintenance expenses include maintenance of the processing plant, maintenance of equipment, maintenance labor, and other directly allocable and attributable maintenance expenses that you can document.</P> <P>(iii) Overhead directly attributable and allocable to the operation and maintenance of the processing plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.</P> <P>(iv) You may use either depreciation with a return on undepreciable capital investment or a return on depreciable capital investment. After you elect to use either method for a processing plant, you may not later elect to change to the other alternative without MMS approval.</P> <P>(A) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves that the processing plant services, or a unit-of-production method. Once you make an election, you may not change methods without MMS approval. A change in ownership of a processing plant will not alter the depreciation schedule that the original processor/lessee established for purposes of the allowance calculation. However, for processing plants you or your affiliate purchase that do not have a previously claimed MMS depreciation schedule, you may treat the processing plant as a newly installed facility for depreciation purposes. A processing plant may be depreciated only once, regardless of whether there is a change in ownership. Equipment may not be depreciated below a reasonable salvage value. To compute a return on undepreciated capital investment, you must multiply the undepreciable capital investment in the processing plant by the rate of return determined under paragraph (b)(2)(v) of this section.</P> <P>(B) To compute a return on depreciable capital investment, you must multiply the initial capital investment in the processing plant by the rate of return determined under paragraph (b)(2)(v) of this section. No allowance will be provided for depreciation. This alternative will apply only to plants first placed in service after March 1, 1988.</P> <P>(v) The rate of return is the industrial rate associated with Standard and Poor's BBB rating. The rate of return is the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.</P> <P>(3) Your processing allowance under this paragraph (b) must be determined based upon a calendar year or other period if you and MMS agree to an alternative.</P> <P>(4) The processing allowance for each gas plant product must be determined based on your reasonable and actual cost of processing the gas. You must base your allocation of costs to each gas plant product upon generally accepted accounting principles. You may not take an allowance for the costs of processing lease production that is not royalty-bearing.</P> <P>(c) <E T="03">Reporting your processing allowance.</E> (1) If MMS requests, you must submit all data used to determine your processing allowance. The data must be provided within a reasonable period of time, as MMS determines.</P> <P>(2) You must report gas processing allowances as a separate line item on the Form MMS-2014. MMS may approve a different reporting procedure for allottee leases, and with lessor approval on tribal leases.</P> <P>(d) <E T="03">Adjusting incorrect processing allowances.</E> If for any month the gas processing allowance you are entitled to is less than the amount you took on Form MMS-2014, you are required to pay additional royalties, plus interest computed under 30 CFR 218.54 from the first day of the first month you deducted a processing allowance until the date you pay the royalties due. If the processing allowance you are entitled is greater than the amount you took on Form MMS-2014, you are entitled to a credit. However, no interest will be paid on the overpayment.</P> <P>(e) <E T="03">Other processing cost determinations.</E> You must follow the provisions of this section to determine processing costs when establishing value using either a net-back valuation procedure or <PRTPAGE P="122"/>any other procedure that requires deduction of actual processing costs.</P> </SECTION> <SECTION> <SECTNO>§ 206.181</SECTNO> <SUBJECT>How do I establish processing costs for dual accounting purposes when I do not process the gas?</SUBJECT> <P>Where accounting for comparison (dual accounting) is required for gas production from a lease but neither you nor someone acting on your behalf processes the gas, and you have elected to perform actual dual accounting under § 206.176, you must use the first applicable of the following methods to establish processing costs for dual accounting purposes:</P> <P>(a) The average of the costs established in your current arm's-length processing agreements for gas from the lease, provided that some gas has previously been processed under these agreements.</P> <P>(b) The average of the costs established in your current arm's-length processing agreements for gas from the lease, provided that the agreements are in effect for plants to which the lease is physically connected and under which gas from other leases in the field or area is being or has been processed.</P> <P>(c) A proposed comparable processing fee submitted to either the tribe and MMS (for tribal leases) or MMS (for allotted leases) with your supporting documentation submitted to MMS. If MMS does not take action on your proposal within 120 days, the proposal will be deemed to be denied and subject to appeal to the MMS Director under 30 CFR part 290.</P> <P>(d) Processing costs based on the regulations in §§ 206.179 and 206.180.</P> </SECTION> </SUBJGRP> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Federal Coal</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>54 FR 1523, Jan. 13, 1989, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 206.250</SECTNO> <SUBJECT>Purpose and scope.</SUBJECT> <P>(a) This subpart is applicable to all coal produced from Federal coal leases. The purpose of this subpart is to establish the value of coal produced for royalty purposes, of all coal from Federal leases consistent with the mineral leasing laws, other applicable laws and lease terms.</P> <P>(b) If the specific provisions of any statute or settlement agreement between the United States and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart then the statute, lease provision, or settlement shall govern to the extent of that inconsistency.</P> <P>(c) All royalty payments made to the Minerals Management Service (MMS) are subject to later audit and adjustment.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5479, Feb. 12, 1996; 67 FR 19111, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.251</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P> <E T="03">Ad valorem lease</E> means a lease where the royalty due to the lessor is based upon a percentage of the amount or value of the coal.</P> <P> <E T="03">Allowance</E> means a deduction used in determining value for royalty purposes. Coal washing allowance means an allowance for the reasonable, actual costs incurred by the lessee for coal washing. Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant.</P> <P> <E T="03">Area</E> means a geographic region in which coal has similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named.</P> <P> <E T="03">Arm's-length contract</E> means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership:</P> <P>(a) Ownership in excess of 50 percent constitutes control;</P> <P>(b) Ownership of 10 through 50 percent creates a presumption of control; and<PRTPAGE P="123"/> </P> <P>(c) Ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates.</P> <FP>Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. The MMS may require the lessee to certify ownership control. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month as well as when the contract was executed.</FP> <P> <E T="03">Audit</E> means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Federal leases.</P> <P> <E T="03">BLM</E> means the Bureau of Land Management of the Department of the Interior.</P> <P> <E T="03">Coal</E> means coal of all ranks from lignite through anthracite.</P> <P> <E T="03">Coal washing</E> means any treatment to remove impurities from coal. Coal washing may include, but is not limited to, operations such as flotation, air, water, or heavy media separation; drying; and related handling (or combination thereof).</P> <P> <E T="03">Contract</E> means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.</P> <P> <E T="03">Gross proceeds</E> (for royalty payment purposes) means the total monies and other consideration accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Federal Government. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.</P> <P> <E T="03">Lease</E> means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States for a Federal coal resource under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of coal—or the land covered by that authorization, whichever is required by the context.</P> <P> <E T="03">Lessee</E> means any person to whom the United States issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.</P> <P> <E T="03">Like-quality coal</E> means coal that has similar chemical and physical characteristics.</P> <P> <E T="03">Marketable condition</E> means coal that is sufficiently free from impurities and otherwise in a condition that it will be accepted by a purchaser under a sales contract typical for that area.</P> <P> <E T="03">Mine</E> means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of lease products.</P> <P> <E T="03">Net-back method</E> means a method for calculating market value of coal at the lease or mine. Under this method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds received for the coal at the first point at which reasonable values for the coal may be determined by a sale pursuant to an arm's-length contract or by comparison to other sales of coal, to ascertain value at the mine.</P> <P> <E T="03">Net output</E> means the quantity of washed coal that a washing plant produces.<PRTPAGE P="124"/> </P> <P> <E T="03">Netting</E> is the deduction of an allowance from the sales value by reporting a one line net sales value, instead of correctly reporting the deduction as a separate line item on the Form MMS-4430.</P> <P> <E T="03">Person</E> means by individual, firm, corporation, association, partnership, consortium, or joint venture.</P> <P> <E T="03">Selling arrangement</E> means the individual contractual arrangements under which sales or dispositions of coal are made to a purchaser.</P> <P> <E T="03">Spot market price</E> means the price received under any sales transaction when planned or actual deliveries span a short period of time, usually not exceeding one year.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 61 FR 5479, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.252</SECTNO> <SUBJECT>Information collection.</SUBJECT> <P>The information collection requirements contained in this subpart have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 <E T="03">et seq.</E> The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10 and 30 CFR 216.10.</P> </SECTION> <SECTION> <SECTNO>§ 206.253</SECTNO> <SUBJECT>Coal subject to royalties—general provisions.</SUBJECT> <P>(a) All coal (except coal unavoidably lost as determined by BLM under 43 CFR part 3400) from a Federal lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease.</P> <P>(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses.</P> <P>(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; <E T="03">i.e.</E>, underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Federal leases shall be allocated to such leases regardless of whether it is stored on Federal lands. The lessee shall maintain accurate records to determine to which individual Federal lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5479, Feb. 12, 1996]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.254</SECTNO> <SUBJECT>Quality and quantity measurement standards for reporting and paying royalties.</SUBJECT> <P>For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information shall be reported on appropriate forms required under 30 CFR part 216 and on the Solid Minerals Production and Royalty Report, Form MMS-4430, as required under 30 CFR part 210.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.255</SECTNO> <SUBJECT>Point of royalty determination.</SUBJECT> <P>(a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Federal coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and MMS.</P> <P>(b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. MMS may ask BLM to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource.</P> <P>(c) The lessee shall pay royalty at a rate specified in the lease at the time <PRTPAGE P="125"/>the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 206.256(d) of this subpart.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.256</SECTNO> <SUBJECT>Valuation standards for cents-per-ton leases.</SUBJECT> <P>(a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty on a cents-per-ton (or other quantity) basis.</P> <P>(b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determine by BLM pursuant to 43 CFR part 3400.</P> <P>(c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal.</P> <P>(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 206.257 of this subpart, and royalties shall be paid at the royalty rate specified in the readjusted lease.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.257</SECTNO> <SUBJECT>Valuation standards for ad valorem leases.</SUBJECT> <P>(a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the value of coal determined under this section, less applicable coal washing allowances and transportation allowances determined under §§ 206.258 through 206.262 of this subpart, or any allowance authorized by § 206.265 of this subpart. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease.</P> <P>(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit.</P> <P>(2) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then the MMS may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration.</P> <P>(3) If the MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the coal production be valued pursuant to paragraph (c)(2) (ii), (iii), (iv), or (v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported coal value.</P> <P>(4) The MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production.</P> <P>(5) The value of production for royalty purposes shall not include payments received by the lessee pursuant <PRTPAGE P="126"/>to a contract which the lessee demonstrates, to MMS's satisfaction, were not part of the total consideration paid for the purchase of coal production.</P> <P>(c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm's-length contract shall be determined in accordance with this section.</P> <P>(2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion:</P> <P>(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition of produced coal by other than an arm's-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm's-length contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: Price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal;</P> <P>(ii) Prices reported for that coal to a public utility commission;</P> <P>(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;</P> <P>(iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain types of coal;</P> <P>(v) If a reasonable value cannot be determined using paragraphs (c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back method or any other reasonable method shall be used to determine value.</P> <P>(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.</P> <P>(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require MMS's prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.</P> <P>(2) Any Federal lessee will make available upon request to the authorized MMS or State representatives, to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm's-length sales value and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area.</P> <P>(3) A lessee shall notify MMS if it has determined value pursuant to paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section. The notification shall be by letter to the Associate Director for Minerals Revenue Management of his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the Form MMS-4430 using a valuation method authorized by paragraphs (c)(2) (ii), (iii), (iv), or (v) of this section, and each time there is a change in a method under paragraphs (c)(2) (iv) or (v) of this section.</P> <P>(e) If MMS determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also be liable for interest computed pursuant to 30 CFR 218.202. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.</P> <P>(f) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a <PRTPAGE P="127"/>value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. The MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.</P> <P>(g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 206.258 through 206.262 and § 206.265 of this subpart.</P> <P>(h) The lessee is required to place coal in marketable condition at no cost to the Federal Government. Where the value established under this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition.</P> <P>(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless MMS approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal.</P> <P>(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed.</P> <P>(k) Certain information submitted to MMS to support valuation proposals, including transportation, coal washing, or other allowances under § 206.265 of this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 55 FR 35433, Aug. 30, 1990; 57 FR 52720, Nov. 5, 1992; 61 FR 5480, Feb. 12, 1996; 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.258</SECTNO> <SUBJECT>Washing allowances—general.</SUBJECT> <P>(a) For ad valorem leases subject to § 206.257 of this subpart, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 206.257 of this subpart was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.</P> <P>(b) If MMS determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any <PRTPAGE P="128"/>additional royalties, plus interest determined in accordance with 30 CFR 218.202, or shall be entitled to a credit without interest.</P> <P>(c) Lessees shall not disproportionately allocate washing costs to Federal leases.</P> <P>(d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing.</P> <P>(e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5480, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.259</SECTNO> <SUBJECT>Determination of washing allowances.</SUBJECT> <P>(a) <E T="03">Arm's-length contracts.</E> (1) For washing costs incurred by a lessee under an arm's-length contract, the washing allowance shall be the reasonable actual costs incurred by the lessee for washing the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. The lessee must claim a washing allowance by reporting it as a separate line entry on the Form MMS-4430.</P> <P>(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then the MMS may require that the washing allowance be determined in accordance with paragraph (b) of this section.</P> <P>(3) If the MMS determines that the consideration paid pursuant to an arm's-length washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the washing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's washing costs.</P> <P>(4) Where the lessee's payments for washing under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed.</P> <P>(b) <E T="03">Non-arm's-length or no contract.</E> (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs washing for itself, the washing allowance will be based upon the lessee's reasonable actual costs. All washing allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. The lessee must claim a washing allowance by reporting it as a separate line entry on the Form MMS-4430. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual washing allowance.</P> <P>(2) The washing allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv) (A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant.</P> <P>(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property <PRTPAGE P="129"/>taxes, rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.</P> <P>(ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.</P> <P>(iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalities, are not allowable expenses.</P> <P>(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of the MMS.</P> <P>(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a wash plant shall not alter the depreciation schedule established by the original operator/lessee for purposes of the allowance calculation. With or without a change in ownership, a wash plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.</P> <P>(B) The MMS shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989.</P> <P>(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.</P> <P>(3) The washing allowance for coal shall be determined based on the lessee's reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing.</P> <P>(c) <E T="03">Reporting requirements</E>—(1) <E T="03">Arm's-length contracts.</E> (i) The lessee must notify MMS of an allowance based on incurred costs by using a separate line entry on the Form MMS-4430.</P> <P>(ii) The MMS may require that a lessee submit arm's-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.</P> <P>(2) <E T="03">Non-arm's-length or no contract.</E> (i) The lessee must notify MMS of an allowance based on the incurred costs by using a separate line entry on the Form MMS-4430.</P> <P>(ii) For new washing facilities or arrangements, the lessee's initial washing deduction shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the washing system or, if such data are not available, the lessee shall use estimates based upon industry data for similar washing systems.</P> <P>(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.</P> <P>(d) <E T="03">Interest and assessments.</E> (1) If a lessee nets a washing allowance on the Form MMS-4430, then the lessee shall be assessed an amount up to 10 percent of the allowance netted not to exceed $250 per lease selling arrangement per sales period.</P> <P>(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.</P> <P>(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.</P> <P>(e) <E T="03">Adjustments.</E> (1) If the actual coal washing allowance is less than the amount the lessee has taken on Form MMS-4430 for each month during the <PRTPAGE P="130"/>allowance reporting period, the lessee shall pay additional royalties due plus interest computed under 30 CFR 218.202 from the date when the lessee took the deduction to the date the lessee repays the difference to MMS. If the actual washing allowance is greater than the amount the lessee has taken on Form MMS-4430 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.</P> <P>(2) The lessee must submit a corrected Form MMS-4430 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.</P> <P>(f) <E T="03">Other washing cost determinations.</E> The provisions of this section shall apply to determine washing costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of washing costs.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 52720, Nov. 5, 1992; 61 FR 5480, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.260</SECTNO> <SUBJECT>Allocation of washed coal.</SUBJECT> <P>(a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted.</P> <P>(b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant.</P> <P>(c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed.</P> </SECTION> <SECTION> <SECTNO>§ 206.261</SECTNO> <SUBJECT>Transportation allowances—general.</SUBJECT> <P>(a) For ad valorem leases subject to § 206.257 of this subpart, where the value for royalty purposes has been determined at a point remote from the lease or mine, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:</P> <P>(1) Transport the coal from a Federal lease to a sales point which is remote from both the lease and mine; or</P> <P>(2) Transport the coal from a Federal lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance.</P> <P>(b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.</P> <P>(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported.</P> <P>(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported.</P> <P>(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid.</P> <P>(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.</P> <P>(e) Lessees shall not disproportionately allocate transportation costs to Federal leases.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 61 FR 5481, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <PRTPAGE P="131"/> <SECTNO>§ 206.262</SECTNO> <SUBJECT>Determination of transportation allowances.</SUBJECT> <P>(a) <E T="03">Arm's-length contracts.</E> (1) For transportation costs incurred by a lessee pursuant to an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. The lessee shall have the burden of demonstrating that its contract is arm's-length. The lessee must claim a transportation allowance by reporting it as a separate line entry on the Form MMS-4430.</P> <P>(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then the MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.</P> <P>(3) If the MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.</P> <P>(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.</P> <P>(b) <E T="03">Non-arm's-length or no contract</E>—(1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable actual costs. All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. The lessee must claim a transportation allowance by reporting it as a separate line entry on the Form MMS-4430. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual transportation allowance deduction.</P> <P>(2) The transportation allowance for non-arm's-length or no-contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.</P> <P>(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.</P> <P>(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.</P> <P>(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for <PRTPAGE P="132"/>a transportation system, the lessee may not later elect to change to the other alternative without approval of the MMS.</P> <P>(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.</P> <P>(B) The MMS shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(B)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989.</P> <P>(v) The rate of return must be the industrial rate associated with Standard and Poor's BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor's Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year.</P> <P>(3) A lessee may apply to MMS for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (b)(2) of this section. MMS will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency or by a State regulatory agency (for Federal leases). MMS shall deny the exception request if it determines that the rate is excessive as compared to arm's-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:</P> <P>(i) No Federal or State regulatory agency costs analysis exists and the Federal or State regulatory agency, as applicable, has declined to investigate under MMS timely objections upon filing; and</P> <P>(ii) The rate significantly exceeds the lessee's actual costs for transportation as determined under this section.</P> <P>(c) <E T="03">Reporting requirements</E>—(1) <E T="03">Arm's-length contracts.</E> (i) The lessee must notify MMS of an allowance based on incurred costs by using a separate line entry on the Form MMS-4430.</P> <P>(ii) The MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.</P> <P>(2) <E T="03">Non-arm's-length or no contract</E>—(i) The lessee must notify MMS of an allowance based on the incurred costs by using a separate line entry on Form MMS-4430.</P> <P>(ii) For new transportation facilities or arrangements, the lessee's initial deduction shall include estimates of the allowable coal transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.</P> <P>(iii) Upon request by MMS, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by MMS.</P> <P>(iv) If the lessee is authorized to use its Federal- or State-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.</P> <P>(d) <E T="03">Interest and assessments.</E> (1) If a lessee nets a transportation allowance on Form MMS-4430, the lessee shall be assessed an amount of up to 10 percent of the allowance netted not to exceed $250 per lease selling arrangement per sales period.<PRTPAGE P="133"/> </P> <P>(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.</P> <P>(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.</P> <P>(e) <E T="03">Adjustments.</E> (1) If the actual coal transportation allowance is less than the amount the lessee has taken on Form MMS-4430 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under 30 CFR 218.202 from the date when the lessee took the deduction to the date the lessee repays the difference to MMS. If the actual transportation allowance is greater than amount the lessee has taken on Form MMS-4430 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest.</P> <P>(2) The lessee must submit a corrected Form MMS-4430 to reflect actual costs, together with any payments, in accordance with instructions provided by MMS.</P> <P>(f) <E T="03">Other transportation cost determinations.</E> The provisions of this section shall apply to determine transportation costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of transportation costs.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 57 FR 41864, Sept. 14, 1992; 57 FR 52720, Nov. 5, 1992; 61 FR 5481, Feb. 12, 1996; 64 FR 43288, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.263</SECTNO> <RESERVED>[Reserved]</RESERVED> </SECTION> <SECTION> <SECTNO>§ 206.264</SECTNO> <SUBJECT>In-situ and surface gasification and liquefaction operations.</SUBJECT> <P>If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to MMS. The MMS will review the lessee's proposal and issue a value determination. The lessee may use its proposed value until MMS issues a value determination.</P> <CITA>[54 FR 1523, Jan. 13, 1989, as amended at 65 FR 43289, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.265</SECTNO> <SUBJECT>Value enhancement of marketable coal.</SUBJECT> <P>If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance with § 206.257(h) of this subpart, the lessee shall notify MMS that such processing is occurring or will occur. The value of that production shall be determined as follows:</P> <P>(a) A value established for the feedstock coal in marketable condition by application of the provisions of § 206.257(c)(2)(i-iv) of this subpart; or,</P> <P>(b) In the event that a value cannot be established in accordance with subsection (a), then the value of production will be determined in accordance with § 206.257(c)(2)(v) of this subpart and the value shall be the lessee's gross proceeds accruing from the disposition of the enhanced product, reduced by MMS-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor's BBB bond rate applicable under § 206.259(b)(2)(v) of this subpart.</P> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart G—Other Solid Minerals</HD> <SECTION> <SECTNO>§ 206.301</SECTNO> <SUBJECT>Value basis for royalty computation.</SUBJECT> <P>(a) The gross value for royalty purposes shall be the sale or contract unit price times the number of units sold, <E T="03">Provided, however,</E> That where the authorized officer determines:</P> <P>(1) That a contract of sale or other business arrangement between the lessee and a purchaser of some or all of the commodities produced from the lease is not a bona fide transaction between independent parties because it is based in whole or in part upon considerations other than the value of the commodities, or</P> <P>(2) That no bona fide sales price is received for some or all of such commodities because the lessee is consuming them, the authorized officer shall determine their gross value, taking into account: (i) All prices received by the lessee in all bona fide transactions, (ii) Prices paid for commodities of like quality produced from the same general area, and (iii) Such other relevant factors as the authorized officer may <PRTPAGE P="134"/>deem appropriate; and <E T="03">Provided further,</E> That in a situation where an estimated value is used, the authorized officer shall require the payment of such additional royalties, or allow such credits or refunds as may be necessary to adjust royalty payment to reflect the actual gross value.</P> <P>(b) The lessee is required to certify that the values reported for royalty purposes are bona fide sales not involving considerations other than the sale of the mineral, and he may be required by the authorized officer to supply supporting information.</P> <CITA>[43 FR 10341, Mar. 13, 1978. Redesignated at 48 FR 36588, Aug. 12, 1983, and amended at 48 FR 44795, Sept. 30, 1983. Further redesignated at 51 FR 15212, Apr. 22, 1986. Redesignated at 53 FR 39461, Oct. 7, 1988]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Geothermal Resources</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>72 FR 24459, May 2, 2007, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 206.350</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <P>(a) This subpart applies to all geothermal resources produced from Federal geothermal leases issued pursuant to the Geothermal Steam Act of 1970 (GSA), as amended by the Energy Policy Act of 2005 (EPAct) (30 U.S.C. 1001 <E T="03">et seq.</E>). The purpose of this subpart is to prescribe how to calculate royalties and direct use fees for geothermal production.</P> <P>(b) The MMS may audit and adjust all royalty and fee payments.</P> <P>(c) In some cases, the regulations in this subpart may be inconsistent with a statute, settlement agreement, written agreement, or lease provision. If this happens, the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency. For purposes of this paragraph, the following definitions apply:</P> <P>(1) “Settlement agreement” means a settlement agreement between the United States and a lessee resulting from administrative or judicial litigation.</P> <P>(2) “Written agreement” means a written agreement between the lessee and the MMS Director or Assistant Secretary, Land and Minerals Management of the Department of the Interior that:</P> <P>(i) Establishes a method to determine the royalty from any lease that MMS expects at least would approximate the value or royalty established under this subpart; and</P> <P>(ii) Includes a value or gross proceeds determination under § 206.364 of this subpart.</P> </SECTION> <SECTION> <SECTNO>§ 206.351</SECTNO> <SUBJECT>What definitions apply to this subpart?</SUBJECT> <P>For purposes of this subpart, the following terms have the meanings indicated.</P> <P> <E T="03">Affiliate</E> means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart:</P> <P>(1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that MMS may rebut.</P> <P>(2) If there is ownership or common ownership of 10 through 50 percent of the voting securities, or instruments of ownership, or other forms of ownership of another person, MMS will consider the following factors in determining whether there is control under the circumstances of a particular case:</P> <P>(i) The extent to which there are common officers or directors;</P> <P>(ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership;</P> <P>(iii) Operation of a lease, plant, pipeline, or other facility;</P> <P>(iv) The extent of participation by other owners in operations and day-to-day management of a lease, plant, pipeline, or other facility; and</P> <P>(v) Other evidence of power to exercise control over or common control with another person.<PRTPAGE P="135"/> </P> <P>(3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates.</P> <P> <E T="03">Allowance</E> means a deduction in determining value for royalty purposes.</P> <P> <E T="03">Arm's-length contract</E> means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm's length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed.</P> <P> <E T="03">Audit</E> means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty or fee payment compliance activities of lessees or other interest holders who pay royalties, fees, rents, or bonuses on Federal geothermal leases.</P> <P> <E T="03">Byproducts</E> means minerals (exclusive of oil, hydrocarbon gas, and helium), found in solution or in association with geothermal steam, that no person would extract and produce by themselves because they are worth less than 75 percent of the value of the geothermal steam or because extraction and production would be too difficult.</P> <P> <E T="03">Byproduct recovery facility</E> means a facility where byproducts are placed in marketable condition.</P> <P> <E T="03">Byproduct transportation allowance</E> means an allowance for the reasonable, actual costs of moving byproducts to a point of sale or delivery off the lease, unit area, or communitized area, or away from a byproduct recovery facility. The byproduct transportation allowance does not include gathering costs. You must report a byproduct transportation allowance as a separate discrete field on the Form MMS-2014.</P> <P> <E T="03">Class I lease</E> means:</P> <P>(1) A lease that BLM issued before August 8, 2005, for which the lessee has not converted the royalty rate terms under 43 CFR 3212.25; or</P> <P>(2) A lease that BLM issued in response to an application that was pending on August 8, 2005, for which the lessee has not made an election under 43 CFR 3200.8(b).</P> <P> <E T="03">Class II lease</E> means:</P> <P>A lease that BLM issued after August 8, 2005, except for a lease issued in response to an application that was pending on August 8, 2005, for which the lessee does not make an election under 43 CFR 3200.8(b).</P> <P> <E T="03">Class III lease</E> means:</P> <P>A lease that BLM issued before August 8, 2005, for which the lessee has converted to the royalty rate or direct use fee terms under 43 CFR 3212.25.</P> <P> <E T="03">Commercial production or generation of electricity</E> means generation of electricity that is sold or is subject to sale, including the electricity or energy that is reasonably required to produce the resource used in production of electricity for sale or to convert geothermal energy into electrical energy for sale.</P> <P> <E T="03">Contract</E> means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.</P> <P> <E T="03">Deduction</E> means a subtraction the lessee uses to determine the value of geothermal resources produced from a Class I lease that the lessee uses to generate electricity.</P> <P> <E T="03">Delivered electricity</E> means the amount of electricity in kilowatt-hours delivered to the purchaser.</P> <P> <E T="03">Direct use</E> means the utilization of geothermal resources for commercial, residential, agricultural, public facilities, or other energy needs, other than the commercial production or generation of electricity.</P> <P> <E T="03">Direct use facility</E> means a facility that uses the heat or other energy of the geothermal resource for direct use purposes.</P> <P> <E T="03">Electrical facility</E> means a power plant or other facility that uses a geothermal resource to generate electricity.</P> <P> <E T="03">Field</E> means the land surface vertically projected over a subsurface geothermal reservoir encompassing at least the outermost boundaries of all geothermal accumulations known to be within that reservoir. Geothermal fields are usually given names and their official boundaries are often designated by regulatory agencies in the respective States in which the fields are located.<PRTPAGE P="136"/> </P> <P> <E T="03">Gathering</E> means the movement of lease production from the wellhead to the point of utilization.</P> <P> <E T="03">Generating deduction</E> means a deduction for the lessee's reasonable, actual costs of generating plant tailgate electricity.</P> <P> <E T="03">Geothermal resources</E> means:</P> <P>(1) All products of geothermal processes, including indigenous steam, hot water, and hot brines;</P> <P>(2) Steam and other gases, hot water, and hot brines resulting from water, gas, or other fluids artificially introduced into geothermal formations;</P> <P>(3) Heat or other associated energy found in geothermal formations; and</P> <P>(4) Any byproducts.</P> <P> <E T="03">Gross proceeds</E> (for royalty payment purposes) means the total monies and other consideration accruing to a geothermal lessee for the sale of electricity or geothermal resource. Gross proceeds includes, but is not limited to:</P> <P>(1) Payments to the lessee for certain services such as effluent injection, field operation and maintenance, drilling or workover of wells, or field gathering to the extent that the lessee is obligated to perform such functions at no cost to the Federal Government;</P> <P>(2) Reimbursements for production taxes and other taxes. Tax reimbursements are part of gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation; and</P> <P>(3) Any monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts.</P> <P> <E T="03">Lease</E> means a geothermal lease issued under the authority of the GSA, unless the context indicates otherwise.</P> <P> <E T="03">Lessee (you)</E> means any person to whom the United States issues a geothermal lease, and any person who has been assigned an obligation to make royalty, fee, or other payments required by the lease. This includes any person who has an interest in a geothermal lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty, fee, or other payment responsibility. This also includes any affiliate of the lessee that uses the geothermal resource to generate electricity, in a direct use process, or to recover byproducts, or any affiliate that sells or transports lease production.</P> <P> <E T="03">Marketable condition</E> means lease products that are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the disposition from the field or area of such lease products.</P> <P> <E T="03">Person</E> means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity).</P> <P> <E T="03">Plant parasitic electricity</E> means electricity used to operate a power plant that is used for commercial production or generation of electricity.</P> <P> <E T="03">Plant tailgate electricity</E> means the amount of electricity in kilowatt-hours generated by a power plant exclusive of plant parasitic electricity, but inclusive of any electricity generated by the power plant and returned to the lease for lease operations. Plant tailgate electricity should be measured at, or calculated for, the high voltage side of the transformer in the plant switchyard.</P> <P> <E T="03">Point of utilization</E> means the power plant or direct use facility in which the geothermal resource is utilized.</P> <P> <E T="03">Public purpose</E> means a program carried out by a State, tribal, or local government for the purpose of providing facilities or services for the benefit of the public in connection with, but not limited to, public health, safety or welfare, other than the commercial generation of electricity. Use of lands or facilities for habitation, cultivation, trade or manufacturing is permissible only when necessary for and integral to (i.e., an essential part of) the public purpose.</P> <P> <E T="03">Public safety or welfare</E> means a program carried out or promoted by a public agency for public purposes involving, directly or indirectly, protection, safety, and law enforcement activities, and the criminal justice system of a given political area. Public safety or welfare may include, but is not limited to, programs carried out by:</P> <P>(1) Public police departments;</P> <P>(2) Sheriffs' offices;</P> <P>(3) The courts;<PRTPAGE P="137"/> </P> <P>(4) Penal and correctional institutions (including juvenile facilities);</P> <P>(5) State and local civil defense organizations; and</P> <P>(6) Fire departments and rescue squads (including volunteer fire departments and rescue squads supported in whole or in part with public funds).</P> <P> <E T="03">Reasonable alternative fuel</E> means a conventional fuel (such as coal, oil, gas, or wood) that would normally be used as a source of heat in direct use operations.</P> <P> <E T="03">Secretary</E> means the Secretary of the Interior or any person duly authorized to exercise the powers vested in that office.</P> <P> <E T="03">Transmission deduction</E> means a deduction for the lessee's reasonable actual costs incurred to wheel or transmit the electricity from the lessee's power plant to the purchaser's delivery point.</P> <P> <E T="03">Wheeling</E> means the transmission of electricity from a power plant to the point of delivery.</P> </SECTION> <SECTION> <SECTNO>§ 206.352</SECTNO> <SUBJECT>How do I calculate the royalty due on geothermal resources used for commercial production or generation of electricity?</SUBJECT> <P>(a) If you sold geothermal resources produced from a Class I, II, or III lease at arm's length that the purchaser uses to generate electricity, then the royalty on the geothermal resources is the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser multiplied by either:</P> <P>(1) The royalty rate in your lease; or</P> <P>(2) The royalty rate that BLM prescribes or calculates under 43 CFR 3211.17. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales.</P> <P>(b) If you use the geothermal resource in your own power plant for the generation and sale of electricity, the following provisions apply</P> <P>(1) For Class I leases, you must determine the royalty on produced geothermal resources in accordance with the first applicable of the following paragraphs:</P> <P>(i) The gross proceeds accruing to you from the arm's-length sale of the electricity less applicable deductions determined under § 206.353 and § 206.354 of this part, multiplied by the royalty rate in your lease. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales. Under no circumstances may the deductions reduce the royalty value of the geothermal resource to zero; or</P> <P>(ii) A royalty determined by any other reasonable method approved by MMS under § 206.364 of this subpart.</P> <P>(2) For Class II and Class III leases, the royalty on geothermal resources produced is your gross proceeds from the sale of electricity multiplied by the royalty rate BLM prescribed for your lease under 43 CFR 3211.17. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales. You may not reduce gross proceeds by any deductions.</P> </SECTION> <SECTION> <SECTNO>§ 206.353</SECTNO> <SUBJECT>How do I determine transmission deductions?</SUBJECT> <P>(a) If you determine the value of your geothermal resources under § 206.352(b)(1)(i) of this subpart, you may subtract a transmission deduction from the gross proceeds you received for the sale of electricity to determine the plant tailgate value of the electricity.</P> <P>(1) The transmission deduction consists of either or both of two components:</P> <P>(i) Transmission line costs as determined under paragraph (b) of this section; and</P> <P>(ii) Wheeling costs if the electricity is transmitted across a third party's transmission line under an arm's-length wheeling agreement.</P> <P>(2) You may deduct the actual costs you (including your affiliate(s)) incur for transmitting electricity under your arm's-length wheeling contract.</P> <P>(b) To determine your transmission line cost, you must follow the requirements of paragraphs (b)(1) and (b)(2) of this section.</P> <P>(1) Your transmission line costs are your actual costs associated with the construction and operation of a transmission line for the purpose of transmitting electricity attributable and allocable to your power plant utilizing Federal geothermal resources.</P> <P>(i) You must determine the monthly transmission line cost component of <PRTPAGE P="138"/>the transmission deduction by multiplying the annual transmission line cost rate (in dollars per kilowatt-hour) by the amount of electricity delivered for the reporting month.</P> <P>(ii) You must redetermine the transmission line cost rate annually either at the beginning of the same month of the year in which the power plant was placed into service or at a time concurrent with the beginning of your annual corporate accounting period. The period you select must coincide with the same period you chose for the generating deduction under § 206.354(b)(1). After you choose a deduction period, you may not later elect to use a different deduction period without MMS approval.</P> <P>(2) Your actual transmission line costs during the reporting period include:</P> <P>(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;</P> <P>(ii) Overhead under paragraph (f) of this section; and either</P> <P>(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section or</P> <P>(iv) A return on the capital investment in the transmission line under paragraphs (g) and (j) of this section.</P> <P>(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transmission line.</P> <P>(2)(i) You may include a return on capital you invested in the purchase of real estate for transmission facilities if:</P> <P>(A) Such purchase is necessary; and</P> <P>(B) The surface is not part of the Federal lease.</P> <P>(ii) The rate of return will be the same rate determined under paragraph (k) of this section.</P> <P>(d) Allowable operating expenses include:</P> <P>(1) Operations supervision and engineering;</P> <P>(2) Operations labor;</P> <P>(3) Fuel;</P> <P>(4) Utilities;</P> <P>(5) Materials;</P> <P>(6) Ad valorem property taxes;</P> <P>(7) Rent;</P> <P>(8) Supplies; and</P> <P>(9) Any other directly allocable and attributable operating or maintenance expense that you can document.</P> <P>(e) Allowable maintenance expenses include:</P> <P>(1) Maintenance of the transmission line;</P> <P>(2) Maintenance of equipment;</P> <P>(3) Maintenance labor; and</P> <P>(4) Other directly allocable and attributable maintenance expenses that you can document.</P> <P>(f) Overhead directly attributable and allocable to the operation and maintenance of the transmission line is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(g) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment in the transmission line. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval.</P> <P>(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract, or other depreciation period acceptable to MMS. You may not depreciate equipment below a reasonable salvage value.</P> <P>(2) A change in ownership of a transmission line does not alter the depreciation schedule established by the original lessee-owner for purposes of computing transmission line costs.</P> <P>(3) With or without a change in ownership, you may depreciate a transmission line only once.</P> <P>(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transmission deduction by the rate of return provided in paragraph (k) of this section.</P> <P>(j) To compute a return on capital investment in the transmission line, <PRTPAGE P="139"/>multiply the allowable capital investment in the transmission line by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.</P> <P>(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. Redetermine the rate at the beginning of each subsequent calendar year.</P> <P>(l) Calculate the deduction for transmission costs based on your cost of transmitting electricity through each individual transmission line.</P> <P>(m)(1) For new transmission facilities or arrangements, base your initial deduction on estimates of allowable electricity transmission costs for the applicable period. Use the most recently available operations data for the transmission line or, if such data are not available, use estimates based on data for similar transmission lines.</P> <P>(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual transmission costs deductions for each month for which you reported and paid based on estimated transmission costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.</P> <P>(n) In conducting reviews and audits, MMS may require you to submit arm's-length transmission contracts, production agreements, operating agreements, and related documents and all other data used to calculate the deduction. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.</P> <P>(o) At the completion of transmission line dismantlement and salvage operations, you may report a credit for or request a refund of royalties in an amount equal to the royalty rate times the amount by which actual transmission line dismantlement costs exceed actual income attributable to salvage of the transmission line.</P> </SECTION> <SECTION> <SECTNO>§ 206.354</SECTNO> <SUBJECT>How do I determine generating deductions?</SUBJECT> <P>(a) If you determine the value of your geothermal resources under § 206.352(b)(1)(i) of this subpart, you may deduct your reasonable actual costs incurred to generate electricity from the plant tailgate value of the electricity (usually the transmission-reduced value of the delivered electricity). You may deduct the actual costs you incur for generating electricity under your arm's-length power plant contract.</P> <P>(b)(1) You must base your generating costs deduction on your actual annual costs associated with the construction and operation of a geothermal power plant.</P> <P>(i) You must determine your monthly generating deduction by multiplying the annual generating cost rate (in dollars per kilowatt-hour) by the amount of plant tailgate electricity measured (or computed) for the reporting month. The generating cost rate is determined from the annual amount of your plant tailgate electricity.</P> <P>(ii) You must redetermine your generating cost rate annually either at the beginning of the same month of the year in which the power plant was placed into service or at a time concurrent with the beginning of your annual corporate accounting period. The period you select must coincide with the same period chosen for the transmission deduction under § 206.353(b)(1). After you choose a deduction period, you may not later elect to use a different deduction period without MMS approval.</P> <P>(2) Your generating costs are your actual power plant costs during the reporting period, including:</P> <P>(i) Operating and maintenance expenses under paragraphs (d) and (e) of this section;</P> <P>(ii) Overhead under paragraph (f) of this section; and either</P> <P>(iii) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section; or</P> <P>(iv) A return on capital investment in the power plant under paragraphs (g) and (j) of this section.<PRTPAGE P="140"/> </P> <P>(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the power plant or are required by the design specifications of the power conversion cycle.</P> <P>(2)(i) You may include a return on capital you invested in the purchase of real estate for a power plant site if:</P> <P>(A) The purchase is necessary; and,</P> <P>(B) The surface is not part of the Federal lease.</P> <P>(ii) The rate of return will be the same rate determined under paragraph (k) of this section.</P> <P>(3) You may not deduct the costs of gathering systems and other production-related facilities.</P> <P>(d) Allowable operating expenses include:</P> <P>(1) Operations supervision and engineering;</P> <P>(2) Operations labor;</P> <P>(3) Auxiliary fuel and/or utilities used to operate the power plant during down time;</P> <P>(4) Utilities;</P> <P>(5) Materials;</P> <P>(6) Ad valorem property taxes;</P> <P>(7) Rent;</P> <P>(8) Supplies; and</P> <P>(9) Any other directly allocable and attributable operating expense.</P> <P>(e) Allowable maintenance expenses include:</P> <P>(1) Maintenance of the power plant;</P> <P>(2) Maintenance of equipment;</P> <P>(3) Maintenance labor; and</P> <P>(4) Other directly allocable and attributable maintenance expenses that you can document.</P> <P>(f) Overhead directly attributable and allocable to the operation and maintenance of the power plant is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(g) To compute costs associated with capital investment, a lessee may use either depreciation with a return on undepreciated capital investment, or a return on capital investment in the power plant. After a lessee has elected to use either method, the lessee may not later elect to change to the other alternative without MMS approval.</P> <P>(h)(1) To compute depreciation, you must use a straight-line depreciation method based on the life of the geothermal project, usually the term of the electricity sales contract, or other depreciation period acceptable to MMS. You may not depreciate equipment below a reasonable salvage value.</P> <P>(2) A change in ownership of the power plant does not alter the depreciation schedule established by the original lessee-owner for purposes of computing generating costs.</P> <P>(3) With or without a change in ownership, you may depreciate a power plant only once.</P> <P>(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the generating deduction allowance by the rate of return provided in paragraph (k) of this section.</P> <P>(j) To compute a return on capital investment in the power plant, multiply the allowable capital investment in the power plant by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.</P> <P>(k) The rate of return must be 2.0 multiplied by the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. You must redetermine the rate at the beginning of each subsequent calendar year.</P> <P>(l) Calculate the deduction for generating costs based on your cost of generating electricity through each individual power plant.</P> <P>(m)(1) For new power plants or arrangements, base your initial deduction on estimates of allowable electricity generation costs for the applicable period. Use the most recently available operations data for the power plant or, if such data are not available, use estimates based on data for similar power plants.</P> <P>(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual generating cost deductions for each month for which you reported and <PRTPAGE P="141"/>paid based on estimated generating costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.</P> <P>(n) In conducting reviews and audits, MMS may require you to submit arm's-length power plant contracts, production agreements, operating agreements, related documents and all other data used to calculate the deduction. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.</P> <P>(o) At the completion of power plant dismantlement and salvage operations, you may report a credit for or request a refund of royalty in an amount equal to the royalty rate times the amount by which actual power plant dismantlement costs exceed actual income attributable to salvage of the power plant.</P> </SECTION> <SECTION> <SECTNO>§ 206.355</SECTNO> <SUBJECT>How do I calculate royalty due on geothermal resources I sell at arm's length to a purchaser for direct use?</SUBJECT> <P>If you sell geothermal resources produced from Class I, II, or III leases at arm's length to a purchaser for direct use, then the royalty on the geothermal resource is the gross proceeds accruing to you from the sale of the geothermal resource to the arm's-length purchaser multiplied by the royalty rate in your lease or that BLM prescribes under 43 CFR 3211.18. See § 206.361 for additional provisions applicable to determining gross proceeds under arm's-length sales.</P> </SECTION> <SECTION> <SECTNO>§ 206.356</SECTNO> <SUBJECT>How do I calculate royalty or fees due on geothermal resources I use for direct use purposes?</SUBJECT> <P>If you use the geothermal resource for direct use:</P> <P>(a) For Class I leases, you must determine the royalty due on geothermal resources in accordance with the first applicable of the following three paragraphs.</P> <P>(1) The weighted average of the gross proceeds established in arm's-length contracts for the purchase of significant quantities of geothermal resources to operate the lessee's same direct-use facility multiplied by the royalty rate in your lease. In evaluating the acceptability of arm's-length contracts, the following factors will be considered: time of execution, duration, terms, volume, quality of resource, and such other factors as may be appropriate to reflect the value of the resource.</P> <P>(2) The equivalent value of the least expensive, reasonable alternative energy source (fuel) multiplied by the royalty rate in your lease. The equivalent value of the least expensive, reasonable alternative energy source will be based on the amount of thermal energy that would otherwise be used by the direct use facility in place of the geothermal resource. That amount of thermal energy (in Btu) displaced by the geothermal resource will be determined by the equation:</P> <MATH DEEP="31" SPAN="2"> <MID>ER02MY07.003</MID> </MATH> <FP>Where h<E T="52">in</E> is the enthalpy in Btu/lb at the direct use facility inlet (based on measured inlet temperature), h<E T="52">out</E> is the enthalpy in Btu/lb at the facility outlet (based on measured outlet temperature), density is in lbs/cu ft based on inlet temperature, the factor 0.113681 (cu ft/gal) converts gallons to cubic feet, and volume is the quantity of geothermal fluid in gallons produced at the wellhead or measured at an approved point. The efficiency factor of the alternative energy source will be 0.7 for coal and 0.8 for oil, natural gas, and other fuels derived from oil and natural gas, or an efficiency factor proposed by the lessee and approved by <PRTPAGE P="142"/>MMS. The methods of measuring resource parameters (temperature, volume, etc.) and the frequency of computing and accumulating the amount of thermal energy displaced will be determined and approved by BLM under 43 CFR 3275.13-3275.17.</FP> <P>(3) A royalty determined by any other reasonable method approved by MMS or the Assistant Secretary, Land and Minerals Management of the Department of the Interior, under § 206.364 of this part.</P> <P>(b) For geothermal resources produced from Class II and Class III leases, you must multiply the appropriate fee from the schedule in subparagraph (b)(1) of this section by the number of gallons or pounds you produce from the direct use lease each month.</P> <P>(1) You must use the following fee schedule to calculate fees due under this section:</P> <GPOTABLE CDEF="s50,12,12,12" COLS="4" OPTS="L2"> <TTITLE>Direct Use Fee Schedule</TTITLE> <TDESC>[Hot water]</TDESC> <BOXHD> <CHED H="1">If your average monthly inlet temperature ( °F) is</CHED> <CHED H="2">At least . . .</CHED> <CHED H="2">But less than . . .</CHED> <CHED H="1">Your fees are . . .</CHED> <CHED H="2">($/million gallons)</CHED> <CHED H="2">($/million pounds)</CHED> </BOXHD> <ROW> <ENT I="01">130</ENT> <ENT>140</ENT> <ENT>2.524</ENT> <ENT>0.307</ENT> </ROW> <ROW> <ENT I="01">140</ENT> <ENT>150</ENT> <ENT>7.549</ENT> <ENT>0.921</ENT> </ROW> <ROW> <ENT I="01">150</ENT> <ENT>160</ENT> <ENT>12.543</ENT> <ENT>1.536</ENT> </ROW> <ROW> <ENT I="01">160</ENT> <ENT>170</ENT> <ENT>17.503</ENT> <ENT>2.150</ENT> </ROW> <ROW> <ENT I="01">170</ENT> <ENT>180</ENT> <ENT>22.426</ENT> <ENT>2.764</ENT> </ROW> <ROW> <ENT I="01">180</ENT> <ENT>190</ENT> <ENT>27.310</ENT> <ENT>3.379</ENT> </ROW> <ROW> <ENT I="01">190</ENT> <ENT>200</ENT> <ENT>32.153</ENT> <ENT>3.993</ENT> </ROW> <ROW> <ENT I="01">200</ENT> <ENT>210</ENT> <ENT>36.955</ENT> <ENT>4.607</ENT> </ROW> <ROW> <ENT I="01">210</ENT> <ENT>220</ENT> <ENT>41.710</ENT> <ENT>5.221</ENT> </ROW> <ROW> <ENT I="01">220</ENT> <ENT>230</ENT> <ENT>46.417</ENT> <ENT>5.836</ENT> </ROW> <ROW> <ENT I="01">230</ENT> <ENT>240</ENT> <ENT>51.075</ENT> <ENT>6.450</ENT> </ROW> <ROW> <ENT I="01">240</ENT> <ENT>250</ENT> <ENT>55.682</ENT> <ENT>7.064</ENT> </ROW> <ROW> <ENT I="01">250</ENT> <ENT>260</ENT> <ENT>60.236</ENT> <ENT>7.679</ENT> </ROW> <ROW> <ENT I="01">260</ENT> <ENT>270</ENT> <ENT>64.736</ENT> <ENT>8.293</ENT> </ROW> <ROW> <ENT I="01">270</ENT> <ENT>280</ENT> <ENT>69.176</ENT> <ENT>8.907</ENT> </ROW> <ROW> <ENT I="01">280</ENT> <ENT>290</ENT> <ENT>73.558</ENT> <ENT>9.521</ENT> </ROW> <ROW> <ENT I="01">290</ENT> <ENT>300</ENT> <ENT>77.876</ENT> <ENT>10.136</ENT> </ROW> <ROW> <ENT I="01">300</ENT> <ENT>310</ENT> <ENT>82.133</ENT> <ENT>10.750</ENT> </ROW> <ROW> <ENT I="01">310</ENT> <ENT>320</ENT> <ENT>86.328</ENT> <ENT>11.364</ENT> </ROW> <ROW> <ENT I="01">320</ENT> <ENT>330</ENT> <ENT>90.445</ENT> <ENT>11.979</ENT> </ROW> <ROW> <ENT I="01">330</ENT> <ENT>340</ENT> <ENT>94.501</ENT> <ENT>12.593</ENT> </ROW> <ROW> <ENT I="01">340</ENT> <ENT>350</ENT> <ENT>98.481</ENT> <ENT>13.207</ENT> </ROW> <ROW> <ENT I="01">350</ENT> <ENT>360</ENT> <ENT>102.387</ENT> <ENT>13.821</ENT> </ROW> </GPOTABLE> <P>(i) For direct use geothermal resources with an average monthly inlet temperature of 130 °F or less, you must pay only the lease rental.</P> <P>(ii) The MMS, in consultation with BLM, will develop and publish a revised fee schedule in the <E T="04">Federal Register,</E> as needed.</P> <P>(iii) The MMS, in consultation with BLM, will calculate revised fees schedules using the following formulas:</P> <MATH DEEP="55" SPAN="2"> <MID>ER02MY07.004</MID> </MATH> <EXTRACT> <FP>Where:</FP> <FP SOURCE="FP-1">R<E T="52">V</E> = Royalty due as a function of produced volume in the fee schedule, expressed as dollars per million (10<SU>6</SU>) gallons;<PRTPAGE P="143"/> </FP> <FP SOURCE="FP-1">R<E T="52">m</E> = Royalty due as a function of produced mass in the fee schedule, expressed as dollars per million (10<SU>6</SU>) pounds;</FP> <FP SOURCE="FP-1">ρ[rho] = Water density at inlet temperature expressed as lbs per gallon;</FP> <FP SOURCE="FP-1">T<E T="52">in</E> = Measured inlet temperature in °F (as required by BLM under 43 CFR part 3275);</FP> <FP SOURCE="FP-1">T<E T="52">out</E> = Established assumed outlet temperature of 130° F;</FP> <FP SOURCE="FP-1">e = Boiler Efficiency Factor for coal of 70 percent;</FP> <FP SOURCE="FP-1">P<E T="52">prbc</E> = The 3-year historical average of Powder River Basin spot coal prices, as published by the Energy Information Administration, or other recognized authoritative reference source of coal prices, in dollars (per MMBtu);</FP> <FP SOURCE="FP-1">F<E T="52">rr</E> = The assumed Lease Royalty Rate of 10 percent.</FP> </EXTRACT> <P>(2) The fee that you report is subject to monitoring, review, and audit.</P> <P>(3) The schedule of fees established under this paragraph will apply to any Class III lease with respect to any royalty payments previously made when the lease was a Class I lease that were due and owing, and were paid, on or after July 16, 2003. To use this provision, you must provide MMS data showing the amount of geothermal production in pounds or gallons of geothermal fluid to input into the fee schedule (see 43 CFR part 3276).</P> <P>(i) If the royalties you previously paid are less than the fees due under this section, you must pay the difference plus interest on that difference computed under § 218.302.</P> <P>(ii) If the royalties you previously paid are more than the fees due under this section, then you are entitled to a refund or credit from MMS of 50 percent of the overpaid royalties. You are also entitled to a refund or credit of any interest that you paid on the overpaid royalties.</P> <P>(c) For geothermal resources other than hot water, MMS will determine fees on a case-by-case basis.</P> </SECTION> <SECTION> <SECTNO>§ 206.357</SECTNO> <SUBJECT>How do I calculate royalty due on byproducts?</SUBJECT> <P>(a) If you sell byproducts, you must determine the royalty due on the byproducts that are royalty-bearing under:</P> <P>(1) Applicable lease terms of Class I leases and of Class III leases that do not elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2), or</P> <P>(2) Applicable statutory provisions at 30 U.S.C. 1004(a)(2) for Class II leases and for Class III leases that do elect to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005, under 43 CFR 3200.7(a)(2).</P> <P>(b) You must determine the royalty due on the byproducts by multiplying the royalty rate in your lease or that BLM prescribes under 43 CFR 3211.19 by a value of the byproducts determined in accordance with the first applicable of the following subparagraphs:</P> <P>(1) The gross proceeds accruing to you from the arm's-length sale of the byproducts, less any applicable byproduct transportation allowances determined under §§ 206.358 and 206.359. See § 206.361 for additional provisions applicable to determining gross proceeds;</P> <P>(2) Other relevant matters including, but not limited to, published or publicly available spot-market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain byproducts; or</P> <P>(3) Any other reasonable valuation method approved by MMS.</P> </SECTION> <SECTION> <SECTNO>§ 206.358</SECTNO> <SUBJECT>What are byproduct transportation allowances?</SUBJECT> <P>(a) When you determine the value of byproducts at a point off the geothermal lease, unit, or participating area, you are allowed a deduction in determining value, for royalty purposes, for your reasonable, actual costs incurred to:</P> <P>(1) Transport the byproducts from a Federal lease, unit, or participating area to a sales point or point of delivery that is off the lease, unit, or participating area; or</P> <P>(2) Transport the byproducts from a Federal lease, unit, or participating area, or from a geothermal use facility to a byproduct recovery facility when that byproduct recovery facility is off the lease, unit, or participating area and, if applicable, from the recovery facility to a sales point or point of delivery off the lease, unit, or participating area.</P> <P>(b) Costs for transporting geothermal fluids from the lease to the geothermal <PRTPAGE P="144"/>use facility, whether on or off the lease, are not includible in the byproduct transportation allowance.</P> <P>(c)(1) When you transport byproducts from a lease, unit, participating area, or geothermal use facility to a byproduct recovery facility, you are not required to allocate transportation costs between the quantity of marketable byproducts and the rejected waste material. The byproduct transportation allowance is authorized for the total production that is transported. You must express byproduct transportation allowances as a cost per unit of marketable byproducts transported.</P> <P>(2) For byproducts that are extracted on the lease, unit, participating area, or at the geothermal use facility, the byproduct transportation allowance is authorized for the total byproduct that is transported to a point of sale off the lease, unit, or participating area. You must express byproduct transportation allowances as a cost per unit of byproduct transported.</P> <P>(3) You may deduct transportation costs only when you sell, deliver, or otherwise utilize the transported byproduct and report and pay royalties on the byproduct.</P> <P>(d) <E T="03">Reporting requirements.</E> (1) You must use a discrete field on Form MMS-2014 to notify MMS of a transportation allowance.</P> <P>(2) In conducting reviews and audits, MMS may require you to submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. You must comply with any such requirements within the time MMS specifies. Recordkeeping requirements are found at part 212 of this chapter.</P> <P>(e) Byproduct transportation allowances are subject to monitoring, review, and audit. If, after a review or audit, MMS determines that you have improperly determined a byproduct transportation allowance, you must pay any additional royalties due (plus interest computed under § 218.302). You are entitled to a credit for or refund of any overpaid royalties.</P> <P>(f) If you commingled byproducts produced from Federal and non-Federal leases for transportation, you may not disproportionately allocate transportation costs to Federal lease production.</P> </SECTION> <SECTION> <SECTNO>§ 206.359</SECTNO> <SUBJECT>How do I determine byproduct transportation allowances?</SUBJECT> <P>(a) For transportation costs you incur under an arm's-length contract, the transportation allowance will be the reasonable, actual costs you incurred for transporting the byproducts under that contract.</P> <P>(1) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from you to the transporter for the transportation. If the contract reflects more than the total consideration you paid, MMS may require you to determine the byproduct transportation allowance under paragraph (b) of this section.</P> <P>(2) If MMS determines that the consideration you paid under an arm's-length byproduct transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS will require you to determine the byproduct transportation allowance under paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify you and give you an opportunity to provide written information justifying your transportation costs.</P> <P>(3) Where your payments for transportation under an arm's-length contract are not established on a dollars-per-unit basis, you must convert whatever consideration you paid to a dollar value equivalent for the purposes of this section.</P> <P>(b) If you transport the byproduct yourself or under a non-arm's-length transportation arrangement, the byproduct transportation allowance is your reasonable actual costs for transportation during the reporting period, including:</P> <P>(1) Operating and maintenance expenses under paragraphs (d) and (e) of this section;<PRTPAGE P="145"/> </P> <P>(2) Overhead under paragraph (f) of this section; and either</P> <P>(3) Depreciation under paragraphs (g) and (h) of this section and a return on undepreciated capital investment under paragraphs (g) and (i) of this section; or</P> <P>(4) A return on capital investment in the transportation system under paragraphs (g) and (j) of this section.</P> <P>(c)(1) Allowable capital costs under paragraph (b) of this section are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) that are an integral part of the transportation system.</P> <P>(2)(i) You may include a return on capital you invested in the purchase of real estate to locate the byproduct transportation facilities if:</P> <P>(A) The purchase is necessary; and</P> <P>(B) The surface is not part of a Federal lease.</P> <P>(ii) The rate of return will be the same rate determined in paragraph (k) of this section.</P> <P>(3) You may not deduct the costs of gathering systems and other production-related facilities.</P> <P>(d) Allowable operating expenses include:</P> <P>(1) Operations supervision and engineering;</P> <P>(2) Operations labor;</P> <P>(3) Fuel;</P> <P>(4) Utilities;</P> <P>(5) Materials;</P> <P>(6) Ad valorem property taxes;</P> <P>(7) Rent;</P> <P>(8) Supplies; and</P> <P>(9) Any other directly allocable and attributable operating expense that you can document.</P> <P>(e) Allowable maintenance expenses include:</P> <P>(1) Maintenance of the transportation system;</P> <P>(2) Maintenance of equipment;</P> <P>(3) Maintenance labor; and</P> <P>(4) Other directly allocable and attributable maintenance expenses that you can document.</P> <P>(f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(g) To compute costs associated with capital investment, a lessee may use either paragraphs (h) and (i) or paragraph (j) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without MMS approval.</P> <P>(h)(1) To compute depreciation, you must use a straight-line depreciation method based on either the life of the equipment or the life of the geothermal project which the transportation system services. After you choose the basis for depreciation, you may not change that basis without MMS approval. You may not depreciate equipment below a reasonable salvage value.</P> <P>(2) A change in ownership of a transportation system does not alter the depreciation schedule established by the original lessee-owner for purposes of computing transportation costs.</P> <P>(3) With or without a change in ownership, you may depreciate a transportation system only once.</P> <P>(i) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating the transportation allowance by the rate of return provided in paragraph (k) of this section.</P> <P>(j) To compute a return on capital investment in the transportation system, the allowed cost will be the amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (k) of this section. There is no allowance for depreciation.</P> <P>(k) The rate of return must be the industrial rate associated with Standard & Poor's BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor's Bond Guide for the first month for which the allowance is applicable. You must redetermine the rate at the beginning of each subsequent calendar year.</P> <P>(l)(1) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable byproduct transportation costs for the <PRTPAGE P="146"/>applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems.</P> <P>(2) When actual cost information is available, you must amend your prior Form MMS-2014 reports to reflect actual byproduct transportation cost deductions for each month for which you reported and paid based on estimated byproduct transportation costs. You must pay any additional royalties due (together with interest computed under § 218.302). You are entitled to a credit for or a refund of any overpaid royalties.</P> </SECTION> <SECTION> <SECTNO>§ 206.360</SECTNO> <SUBJECT>What records must I keep to support my calculations of royalty or fees under this subpart?</SUBJECT> <P>If you determine royalties or direct use fees for your geothermal resource under this subpart, you must retain all data relevant to the determination of the royalty value or the fee you paid. Recordkeeping requirements are found at part 212 of this chapter.</P> <P>(a) You must be able to show:</P> <P>(1) How you calculated the royalty value or fee you reported, including all allowable deductions; and</P> <P>(2) How you complied with this subpart.</P> <P>(b) Upon request, you must submit all data to MMS. You must comply with any such requirement within the time MMS specifies.</P> </SECTION> <SECTION> <SECTNO>§ 206.361</SECTNO> <SUBJECT>How will MMS determine whether my royalty or direct use fee payments are correct?</SUBJECT> <P>(a)(1) The royalties or direct use fees that you report are subject to monitoring, review, and audit. The MMS may review and audit your data, and MMS will direct you to use a different measure of royalty value, gross proceeds, or fee, whichever is applicable, if it determines that the reported value, gross proceeds, or fee is inconsistent with the requirements of this subpart.</P> <P>(2) If MMS directs you to use a different royalty value, measure of gross proceeds, or fee, you must either pay any royalties or fees due (together with interest computed under § 218.302) or report a credit for or request a refund of any overpaid royalties or fees.</P> <P>(b) When the provisions in this subpart refer to gross proceeds either for the sale of electricity or the sale of a geothermal resource, in conducting reviews and audits MMS will examine whether your sales contract reflects the total consideration actually transferred, either directly or indirectly, from the buyer to you for the geothermal resource or electricity. If MMS determines that a contract does not reflect the total consideration, or the gross proceeds accruing to you under a contract do not reflect reasonable consideration because of misconduct by or between the contracting parties, or because you otherwise have breached your duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, MMS may require you to increase the gross proceeds to reflect any additional consideration. Alternatively, for Class I leases, MMS may require you to use another valuation method in the regulations applicable to dispositions other than under an arm's-length contract. The MMS will notify you to give you an opportunity to provide written information justifying your gross proceeds.</P> <P>(c) For arm's-length sales, you have the burden of demonstrating that your contract is arm's length.</P> <P>(d) The MMS may require you to certify that the provisions in your sales contract include all of the consideration the buyer paid you, either directly or indirectly, for the electricity or geothermal resource.</P> <P>(e) Notwithstanding any other provision of this subpart, under no circumstances will the value of production for royalty purposes under a Class I lease where the geothermal resources are sold before use be less than the gross proceeds accruing to you.</P> <P>(f) Gross proceeds for the sale of electricity or for the sale of the geothermal resource will be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract.</P> <P>(1) Absent contract revision or amendment, if you fail to take proper or timely action to receive prices or benefits to which you are entitled, you <PRTPAGE P="147"/>must pay royalty based upon that obtainable price or benefit.</P> <P>(2) Contract revisions or amendments you make must be in writing and signed by all parties to the contract.</P> <P>(3) If you make timely application for a price increase or benefit allowed under your contract, but the purchaser refuses and you take reasonable measures, which are documented, to force purchaser compliance, you will owe no additional royalties unless or until you receive additional monies or consideration resulting from the price increase. This paragraph (f)(3) will not be construed to permit you to avoid your royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of geothermal resources or electricity.</P> </SECTION> <SECTION> <SECTNO>§ 206.362</SECTNO> <SUBJECT>What are my responsibilities to place production into marketable condition and to market production?</SUBJECT> <P>You must place geothermal resources and byproducts in marketable condition and market the geothermal resources or byproducts for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. If you use gross proceeds under an arm's-length contract in determining royalty, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the geothermal resources or byproducts in marketable condition or to market the geothermal resources or byproducts.</P> </SECTION> <SECTION> <SECTNO>§ 206.363</SECTNO> <SUBJECT>When is an MMS audit, review, reconciliation, monitoring, or other like process considered final?</SUBJECT> <P>Notwithstanding any provision in these regulations to the contrary, no audit, review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of royalty or fees due under this subpart is considered final or binding as against the Federal Government or its beneficiaries until MMS formally closes the audit period in writing.</P> </SECTION> <SECTION> <SECTNO>§ 206.364</SECTNO> <SUBJECT>How do I request a value or gross proceeds determination?</SUBJECT> <P>(a) You may request a value determination from MMS regarding any geothermal resources produced from a Class I lease or for byproducts produced from a Class I, Class II, or Class III lease. You may also request a gross proceeds determination for a Class II or Class III lease. Your request must:</P> <P>(1) Be in writing;</P> <P>(2) Identify specifically all leases involved, all owners of interests in those leases, and the operator(s) for those leases;</P> <P>(3) Completely explain all relevant facts. You must inform MMS of any changes to relevant facts that occur before we respond to your request;</P> <P>(4) Include copies of all relevant documents;</P> <P>(5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and</P> <P>(6) Suggest your proposed gross proceeds calculation or valuation method.</P> <P>(b) In response to your request:</P> <P>(1) The Assistant Secretary, Land and Minerals Management, may issue a determination; or</P> <P>(2) The MMS may issue a determination; or</P> <P>(3) The MMS may inform you in writing that MMS will not provide a determination. Situations in which MMS typically will not provide any determination include, but are not limited to:</P> <P>(i) Requests for guidance on hypothetical situations; and</P> <P>(ii) Matters that are the subject of pending litigation or administrative appeals.</P> <P>(c)(1) A determination signed by the Assistant Secretary, Land and Minerals Management, is binding on both you and MMS until the Assistant Secretary modifies or rescinds it.</P> <P>(2) After the Assistant Secretary issues a determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay the royalties owed together with late payment interest computed under § 218.302.</P> <P>(3) A determination signed by the Assistant Secretary is the final action of <PRTPAGE P="148"/>the Department and is subject to judicial review under 5 U.S.C. 701-706.</P> <P>(d) A determination issued by MMS is binding on MMS and delegated States, but not on you, with respect to the specific situation addressed in the determination unless the MMS (for MMS-issued determinations) or the Assistant Secretary modifies or rescinds it.</P> <P>(1) A determination by MMS is not an appealable decision or order under 30 CFR part 290 subpart B.</P> <P>(2) If you receive an order requiring you to pay royalty on the same basis as the determination, you may appeal that order under 30 CFR part 290 subpart B.</P> <P>(e) In making a determination, MMS or the Assistant Secretary may use any of the applicable criteria in this subpart.</P> <P>(f) A change in an applicable statute or regulation on which any determination is based takes precedence over the determination after the effective date of the statute or regulation, regardless of whether the MMS or the Assistant Secretary modifies or rescinds the determination.</P> <P>(g) The MMS or the Assistant Secretary generally will not retroactively modify or rescind a determination issued under paragraph (d) of this section, unless:</P> <P>(1) There was a misstatement or omission of material facts; or</P> <P>(2) The facts subsequently developed are materially different from the facts on which the guidance was based.</P> <P>(h) The MMS may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 206.365.</P> </SECTION> <SECTION> <SECTNO>§ 206.365</SECTNO> <SUBJECT>Does MMS protect information I provide?</SUBJECT> <P>Certain information you submit to MMS regarding royalties or fees on geothermal resources or byproducts, including deductions and allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, MMS will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2.</P> </SECTION> <SECTION> <SECTNO>§ 206.366</SECTNO> <SUBJECT>What is the nominal fee that a State, tribal, or local government lessee must pay for the use of geothermal resources?</SUBJECT> <P>If a State, tribal, or local government lessee uses a geothermal resource without sale and for public purposes—other than commercial production or generation of electricity—the State, tribal, or local government lessee must pay a nominal fee. A nominal fee means a slight or <E T="03">de minimis</E> fee. The MMS will determine the fee on a case-by-case basis.</P> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart J—Indian Coal</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>61 FR 5481, Feb. 12, 1996, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 206.450</SECTNO> <SUBJECT>Purpose and scope.</SUBJECT> <P>(a) This subpart prescribes the procedures to establish the value, for royalty purposes, of all coal from Indian Tribal and allotted leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma).</P> <P>(b) If the specific provisions of any statute, treaty, or settlement agreement between the Indian lessor and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart, then the statute, treaty, lease provision, or settlement shall govern to the extent of that inconsistency.</P> <P>(c) All royalty payments are subject to later audit and adjustment.</P> <P>(d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian coal leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms.</P> </SECTION> <SECTION> <SECTNO>§ 206.451</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P> <E T="03">Ad valorem lease</E> means a lease where the royalty due to the lessor is based upon a percentage of the amount or value of the coal.<PRTPAGE P="149"/> </P> <P> <E T="03">Allowance</E> means an approved, or an MMS-initially accepted deduction in determining value for royalty purposes. Coal washing allowance means an allowance for the reasonable, actual costs incurred by the lessee for coal washing, or an approved or MMS-initially accepted deduction for the costs of washing coal, determined pursuant to this subpart. Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant, or an approved MMS-initially accepted deduction for costs of such transportation, determined pursuant to this subpart.</P> <P> <E T="03">Area</E> means a geographic region in which coal has similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named.</P> <P> <E T="03">Arm's-length contract</E> means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership: ownership in excess of 50 percent constitutes control; ownership of 10 through 50 percent creates a presumption of control; and ownership of less than 10 percent creates a presumption of noncontrol which MMS may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm's-length contracts. MMS may require the lessee to certify ownership control. To be considered arm's-length for any production month, a contract must meet the requirements of this definition for that production month, as well as when the contract was executed.</P> <P> <E T="03">Audit</E> means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Indian leases.</P> <P> <E T="03">BIA</E> means the Bureau of Indian Affairs of the Department of the Interior.</P> <P> <E T="03">BLM</E> means the Bureau of Land Management of the Department of the Interior.</P> <P> <E T="03">Coal</E> means coal of all ranks from lignite through anthracite.</P> <P> <E T="03">Coal washing</E> means any treatment to remove impurities from coal. Coal washing may include, but is not limited to, operations such as flotation, air, water, or heavy media separation; drying; and related handling (or combination thereof).</P> <P> <E T="03">Contract</E> means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation.</P> <P> <E T="03">Gross proceeds</E> (for royalty payment purposes) means the total monies and other consideration accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Indian lessor. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Indian royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds.</P> <P> <E T="03">Indian allottee</E> means any Indian for whom land or an interest in land is held in trust by the United States or who holds title subject to Federal restriction against alienation.</P> <P> <E T="03">Indian Tribe</E> means any Indian Tribe, band, nation, pueblo, community, <PRTPAGE P="150"/>rancheria, colony, or other group of Indians for which any land or interest in land is held in trust by the United States or which is subject to Federal restriction against alienation.</P> <P> <E T="03">Lease</E> means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States for an Indian coal resource under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of coal—or the land covered by that authorization, whichever is required by the context.</P> <P> <E T="03">Lessee</E> means any person to whom the Indian Tribe or an Indian allottee issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility.</P> <P> <E T="03">Like-quality coal</E> means coal that has similar chemical and physical characteristics.</P> <P> <E T="03">Marketable condition</E> means coal that is sufficiently free from impurities and otherwise in a condition that it will be accepted by a purchaser under a sales contract typical for that area.</P> <P> <E T="03">Mine</E> means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of lease products.</P> <P> <E T="03">MMS</E> means the Minerals Management Service of the Department of the Interior.</P> <P> <E T="03">Net-back method</E> means a method for calculating market value of coal at the lease or mine. Under this method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds received for the coal at the first point at which reasonable values for the coal may be determined by a sale pursuant to an arm's-length contract or by comparison to other sales of coal, to ascertain value at the mine.</P> <P> <E T="03">Net output</E> means the quantity of washed coal that a washing plant produces.</P> <P> <E T="03">Person</E> means by individual, firm, corporation, association, partnership, consortium, or joint venture.</P> <P> <E T="03">Selling arrangement</E> means the individual contractual arrangements under which sales or dispositions of coal are made to a purchaser.</P> <P> <E T="03">Spot market price</E> means the price received under any sales transaction when planned or actual deliveries span a short period of time, usually not exceeding one year.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.452</SECTNO> <SUBJECT>Coal subject to royalties—general provisions.</SUBJECT> <P>(a) All coal (except coal unavoidably lost as determined by BLM pursuant to 43 CFR group 3400) from an Indian lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease.</P> <P>(b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses.</P> <P>(c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; <E T="03">i.e.</E>, underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Indian leases shall be allocated to such leases regardless of whether it is stored on Indian lands. The lessee shall maintain accurate records to determine to which individual Indian lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid.</P> </SECTION> <SECTION> <SECTNO>§ 206.453</SECTNO> <SUBJECT>Quality and quantity measurement standards for reporting and paying royalties.</SUBJECT> <P>For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons <PRTPAGE P="151"/>(of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information shall be reported on appropriate forms required under 30 CFR part 216 and on the Solid Minerals Production and Royalty Report, Form MMS-4430, as required under 30 CFR part 210.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.454</SECTNO> <SUBJECT>Point of royalty determination.</SUBJECT> <P>(a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Indian coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and MMS.</P> <P>(b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. MMS may ask BLM or BIA to increase the lease bond to protect the lessor's interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource.</P> <P>(c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 206.455(d) of this subpart.</P> </SECTION> <SECTION> <SECTNO>§ 206.455</SECTNO> <SUBJECT>Valuation standards for cents-per-ton leases.</SUBJECT> <P>(a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty on a cents-per-ton (or other quantity) basis.</P> <P>(b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determined by BLM pursuant to 43 CFR part 3400.</P> <P>(c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal.</P> <P>(d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 206.456 of this subpart, and royalties shall be paid at the royalty rate specified in the readjusted lease.</P> </SECTION> <SECTION> <SECTNO>§ 206.456</SECTNO> <SUBJECT>Valuation standards for ad valorem leases.</SUBJECT> <P>(a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the value of coal determined pursuant to this section, less applicable coal washing allowances and transportation allowances determined pursuant to §§ 206.457 through 206.461 of this subpart, or any allowance authorized by § 206.464 of this subpart. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease.</P> <P>(b)(1) The value of coal that is sold pursuant to an arm's-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (b)(3), and (b)(5) of this section. The lessee shall have the burden of demonstrating that its contract is arm's-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit.</P> <P>(2) In conducting reviews and audits, MMS will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then MMS may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be <PRTPAGE P="152"/>based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration.</P> <P>(3) If MMS determines that the gross proceeds accruing to the lessee pursuant to an arm's-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the coal production be valued pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When MMS determines that the value may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee's reported coal value.</P> <P>(4) MMS may require a lessee to certify that its arm's-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production.</P> <P>(5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to MMS' satisfaction, were not part of the total consideration paid for the purchase of coal production.</P> <P>(c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm's-length contract shall be determined in accordance with this section.</P> <P>(2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion:</P> <P>(i) The gross proceeds accruing to the lessee pursuant to a sale under its non-arm's-length contract (or other disposition of produced coal by other than an arm's-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm's-length contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm's-length contracts for the purposes of these regulations, the following factors shall be considered: price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal;</P> <P>(ii) Prices reported for that coal to a public utility commission;</P> <P>(iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy;</P> <P>(iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the salability of certain types of coal;</P> <P>(v) If a reasonable value cannot be determined using paragraphs (c)(2)(i), (c)(2)(ii), (c)(2)(iii), or (c)(2)(iv) of this section, then a net-back method or any other reasonable method shall be used to determine value.</P> <P>(3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section.</P> <P>(d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require MMS' prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and MMS will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations.</P> <P>(2) An Indian lessee will make available upon request to the authorized MMS or Indian representatives, or to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm's-length sales and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area.<PRTPAGE P="153"/> </P> <P>(3) A lessee shall notify MMS if it has determined value pursuant to paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section. The notification shall be by letter to the Associate Director for Minerals Revenue Management or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the Form MMS-4430 using a valuation method authorized by paragraphs (c)(2)(ii), (c)(2)(iii), (c)(2)(iv), or (c)(2)(v) of this section, and each time there is a change in a method under paragraphs (c)(2)(iv) or (c)(2)(v) of this section.</P> <P>(e) If MMS determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by MMS. The lessee shall also be liable for interest computed pursuant to 30 CFR 218.202. If the lessee is entitled to a credit, MMS will provide instructions for the taking of that credit.</P> <P>(f) The lessee may request a value determination from MMS. In that event, the lessee shall propose to MMS a value determination method, and may use that method in determining value for royalty purposes until MMS issues its decision. The lessee shall submit all available data relevant to its proposal. MMS shall expeditiously determine the value based upon the lessee's proposal and any additional information MMS deems necessary. That determination shall remain effective for the period stated therein. After MMS issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section.</P> <P>(g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 206.457 through 206.461 and § 206.464 of this subpart.</P> <P>(h) The lessee is required to place coal in marketable condition at no cost to the Indian lessor. Where the value established pursuant to this section is determined by a lessee's gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition.</P> <P>(i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm's-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless MMS approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal.</P> <P>(j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by MMS of value under this section shall be considered final or binding as against the Indian Tribes or allottees until the audit period is formally closed.</P> <P>(k) Certain information submitted to MMS to support valuation proposals, including transportation, coal washing, or other allowances pursuant to §§ 206.457 through 206.461 and § 206.464 of <PRTPAGE P="154"/>this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. Nothing in this section is intended to limit or diminish in any manner whatsoever the right of an Indian lessor to obtain any and all information as such lessor may be lawfully entitled from MMS or such lessor's lessee directly under the terms of the lease or applicable law.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.457</SECTNO> <SUBJECT>Washing allowances—general.</SUBJECT> <P>(a) For ad valorem leases subject to § 206.456 of this subpart, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 206.456 of this subpart was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.</P> <P>(b) If MMS determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.</P> <P>(c) Lessees shall not disproportionately allocate washing costs to Indian leases.</P> <P>(d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing.</P> <P>(e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.458</SECTNO> <SUBJECT>Determination of washing allowances.</SUBJECT> <P>(a) <E T="03">Arm's-length contracts.</E> (1) For washing costs incurred by a lessee pursuant to an arm's-length contract, the washing allowance shall be the reasonable actual costs incurred by the lessee for washing the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. However, before any deduction may be taken, the lessee must submit a completed page one of Form MMS-4292, Coal Washing Allowance Report, in accordance with paragraph (c)(1) of this section. A washing allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4292 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee.</P> <P>(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then MMS may require that the washing allowance be determined in accordance with paragraph (b) of this section.</P> <P>(3) If MMS determines that the consideration paid pursuant to an arm's-length washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the washing may be unreasonable, MMS will notify the lessee and give the lessee an opportunity to provide written <PRTPAGE P="155"/>information justifying the lessee's washing costs.</P> <P>(4) Where the lessee's payments for washing under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed.</P> <P>(b) <E T="03">Non-arm's-length or no contract.</E> (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs washing for itself, the washing allowance will be based upon the lessee's reasonable actual costs. All washing allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. Prior MMS approval of washing allowances is not required for non-arm's-length or no contract situations. However, before any estimated or actual deduction may be taken, the lessee must submit a completed Form MMS-4292 in accordance with paragraph (c)(2) of this section. A washing allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4292 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee. MMS will monitor the allowance deduction to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may direct a lessee to modify its actual washing allowance.</P> <P>(2) The washing allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant.</P> <P>(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.</P> <P>(ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.</P> <P>(iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses.</P> <P>(iv) A lessee may use either paragraph (b)(2)(iv)(A) or (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of MMS.</P> <P>(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a wash plant shall not alter the depreciation schedule established by the original operator/lessee for purposes of the allowance calculation. With or without a change in ownership, a wash plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.</P> <P>(B) MMS shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989.</P> <P>(v) The rate of return shall be the industrial rate associated with Standard <PRTPAGE P="156"/>and Poor's BBB rating. The rate of return shall be the monthly average rate as published in Standard and Poor's Bond Guide for the first month of the reporting period for which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent washing allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section).</P> <P>(3) The washing allowance for coal shall be determined based on the lessee's reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing.</P> <P>(c) <E T="03">Reporting requirements</E>—(1) <E T="03">Arm's-length contracts.</E> (i) With the exception of those washing allowances specified in paragraphs (c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page one of the initial Form MMS-4292 prior to, or at the same time, as the washing allowance determined pursuant to an arm's-length contract is reported on Form MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-4292 received by the end of the month that the Form MMS-4430 is due shall be considered to be received timely.</P> <P>(ii) The initial Form MMS-4292 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.</P> <P>(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4292 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).</P> <P>(iv) MMS may require that a lessee submit arm's-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.</P> <P>(v) Washing allowances which are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.</P> <P>(vi) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.</P> <P>(2) <E T="03">Non-arm's-length or no contract.</E> (i) With the exception of those washing allowances specified in paragraphs (c)(2)(v) and (c)(2)(vii) of this section, the lessee shall submit an initial Form MMS-4292 prior to, or at the same time as, the washing allowance determined pursuant to a non-arm's-length contract or no contract situation is reported on Form MMS-4430, Solid Minerals Production and Royalty Report. A Form MMS-4292 received by the end of the month that the Form MMS-4430 is due shall be considered to be timely received. The initial reporting may be based on estimated costs.</P> <P>(ii) The initial Form MMS-4292 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the washing under the non-arm's-length contract or the no contract situation terminates, whichever is earlier.</P> <P>(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4292 containing the actual costs for the previous reporting period. If coal washing is continuing, the lessee shall include on Form MMS-4292 its estimated costs for the next calendar year. The estimated coal washing allowance shall be based on the actual costs for the previous period plus or minus any adjustments which are based on the lessee's knowledge of decreases or increases which will affect the allowance. Form MMS-4292 must be received by MMS within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee <PRTPAGE P="157"/>shall continue to use the allowance from the previous reporting period).</P> <P>(iv) For new wash plants, the lessee's initial Form MMS-4292 shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant, or if such data are not available, the lessee shall use estimates based upon industry data for similar coal wash plants.</P> <P>(v) Washing allowances based on non-arm's-length or no contract situations which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.</P> <P>(vi) Upon request by MMS, the lessee shall submit all data used by the lessee to prepare its Forms MMS-4292. The data shall be provided within a reasonable period of time, as determined by MMS.</P> <P>(vii) MMS may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section.</P> <P>(3) MMS may establish coal washing allowance reporting dates for individual leases different from those specified in this subpart in order to provide more effective administration. Lessees will be notified of any change in their reporting period.</P> <P>(4) Washing allowances must be reported as a separate line on the Form MMS-4430, unless MMS approves a different reporting procedure.</P> <P>(d) <E T="03">Interest assessments for incorrect or late reports and failure to report.</E> (1) If a lessee deducts a washing allowance on its Form MMS-4430 without complying with the requirements of this section, the lessee shall be liable for interest on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section.</P> <P>(2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.</P> <P>(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.</P> <P>(e) <E T="03">Adjustments.</E> (1) If the actual coal washing allowance is less than the amount the lessee has taken on Form MMS-4430 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest computed pursuant to 30 CFR 218.202, retroactive to the first month the lessee is authorized to deduct a washing allowance. If the actual washing allowance is greater than the amount the lessee has estimated and taken during the reporting period, the lessee shall be entitled to a credit, without interest.</P> <P>(2) The lessee must submit a corrected Form MMS-4430 to reflect actual costs, together with any payment, in accordance with instructions provided by MMS.</P> <P>(f) <E T="03">Other washing cost determinations.</E> The provisions of this section shall apply to determine washing costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of washing costs.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended at 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.459</SECTNO> <SUBJECT>Allocation of washed coal.</SUBJECT> <P>(a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted.</P> <P>(b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant.</P> <P>(c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed.</P> </SECTION> <SECTION> <PRTPAGE P="158"/> <SECTNO>§ 206.460</SECTNO> <SUBJECT>Transportation allowances—general.</SUBJECT> <P>(a) For ad valorem leases subject to § 206.456 of this subpart, where the value for royalty purposes has been determined at a point remote from the lease or mine, MMS shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to:</P> <P>(1) Transport the coal from an Indian lease to a sales point which is remote from both the lease and mine; or</P> <P>(2) Transport the coal from an Indian lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance.</P> <P>(b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero.</P> <P>(c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported.</P> <P>(2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported.</P> <P>(3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid.</P> <P>(d) If, after a review and/or audit, MMS determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with 30 CFR 218.202, or shall be entitled to a credit, without interest.</P> <P>(e) Lessees shall not disproportionately allocate transportation costs to Indian leases.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.461</SECTNO> <SUBJECT>Determination of transportation allowances.</SUBJECT> <P>(a) <E T="03">Arm's-length contracts.</E> (1) For transportation costs incurred by a lessee pursuant to an arm's-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. MMS' prior approval is not required before a lessee may deduct costs incurred under an arm's-length contract. However, before any deduction may be taken, the lessee must submit a completed page one of Form MMS-4293, Coal Transportation Allowance Report, in accordance with paragraph (c)(1) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4293 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee.</P> <P>(2) In conducting reviews and audits, MMS will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then MMS may require that the transportation allowance be determined in accordance with paragraph (b) of this section.</P> <P>(3) If MMS determines that the consideration paid pursuant to an arm's-length transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then MMS shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When MMS determines that the value of the transportation may be unreasonable, MMS will notify the lessee <PRTPAGE P="159"/>and give the lessee an opportunity to provide written information justifying the lessee's transportation costs.</P> <P>(4) Where the lessee's payments for transportation under an arm's-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section.</P> <P>(b) <E T="03">Non-arm's-length or no contract.</E> (1) If a lessee has a non-arm's-length contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee's reasonable actual costs. All transportation allowances deducted under a non-arm's-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. Prior MMS approval of transportation allowances is not required for non-arm's-length or no contract situations. However, before any estimated or actual deduction may be taken, the lessee must submit a completed Form MMS-4293 in accordance with paragraph (c)(2) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that Form MMS-4293 is filed with MMS, unless MMS approves a longer period upon a showing of good cause by the lessee. MMS will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, MMS may direct a lessee to modify its estimated or actual transportation allowance deduction.</P> <P>(2) The transportation allowance for non-arm's-length or no contract situations shall be based upon the lessee's actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system.</P> <P>(i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document.</P> <P>(ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document.</P> <P>(iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses.</P> <P>(iv) A lessee may use either paragraph (b)(2)(iv)(A) or paragraph (b)(2)(iv)(B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of MMS.</P> <P>(A) To compute depreciation, the lessee may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without MMS approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value.</P> <P>(B) MMS shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph <PRTPAGE P="160"/>(b)(2)(B)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989.</P> <P>(v) The rate of return shall be the industrial rate associated with Standard and Poor's BBB rating. The rate of return shall be the monthly average as published in Standard and Poor's Bond Guide for the first month of the reporting period of which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent transportation allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section).</P> <P>(3) A lessee may apply to MMS for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (b)(2) of this section. MMS will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency for Indian leases. MMS shall deny the exception request if it determines that the rate is excessive as compared to arm's-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm's-length transportation charges, MMS shall deny the exception request if:</P> <P>(i) No Federal regulatory agency cost analysis exists and the Federal regulatory agency has declined to investigate pursuant to MMS timely objections upon filing; and</P> <P>(ii) The rate significantly exceeds the lessee's actual costs for transportation as determined under this section.</P> <P>(c) <E T="03">Reporting requirements</E>—(1) <E T="03">Arm's-length contracts.</E> (i) With the exception of those transportation allowances specified in paragraphs (c)(1)(v) and (c)(1)(vi) of this section, the lessee shall submit page one of the initial Form MMS-4293 prior to, or at the same time as, the transportation allowance determined pursuant to an arm's-length contract is reported on Form MMS-4430, Solid Minerals Production and Royalty Report.</P> <P>(ii) The initial Form MMS-4293 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier.</P> <P>(iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of Form MMS-4293 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period). Lessees may request special reporting procedures in unique allowance reporting situations, such as those related to spot sales.</P> <P>(iv) MMS may require that a lessee submit arm's-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by MMS.</P> <P>(v) Transportation allowances that are based on arm's-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.</P> <P>(vi) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.</P> <P>(2) <E T="03">Non-arm's-length or no contract.</E> (i) With the exception of those transportation allowances specified in paragraphs (c)(2)(v) and (c)(2)(vii) of this section, the lessee shall submit an initial Form MMS-4293 prior to, or at the same time as, the transportation allowance determined pursuant to a non-arm's-length contract or no contract situation is reported on Form MMS-4430, Solid Minerals Production and Royalty Report. The initial report may be based on estimated costs.</P> <P>(ii) The initial Form MMS-4293 shall be effective for a reporting period beginning the month that the lessee first <PRTPAGE P="161"/>is authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the transportation under the non-arm's-length contract or the no contract situation terminates, whichever is earlier.</P> <P>(iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed Form MMS-4293 containing the actual costs for the previous reporting period. If the transportation is continuing, the lessee shall include on Form MMS-4293 its estimated costs for the next calendar year. The estimated transportation allowance shall be based on the actual costs for the previous reporting period plus or minus any adjustments that are based on the lessee's knowledge of decreases or increases that will affect the allowance. Form MMS-4293 must be received by MMS within 3 months after the end of the previous reporting period, unless MMS approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period).</P> <P>(iv) For new transportation facilities or arrangements, the lessee's initial Form MMS-4293 shall include estimates of the allowable transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system, or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems.</P> <P>(v) Non-arm's-length contract or no contract-based transportation allowances that are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For purposes of this section, only those allowances that have been approved by MMS in writing shall qualify as being in effect at the time these regulations become effective.</P> <P>(vi) Upon request by MMS, the lessee shall submit all data used to prepare its Form MMS-4293. The data shall be provided within a reasonable period of time, as determined by MMS.</P> <P>(vii) MMS may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section.</P> <P>(viii) If the lessee is authorized to use its Federal-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section.</P> <P>(3) MMS may establish reporting dates for individual lessees different than those specified in this paragraph in order to provide more effective administration. Lessees will be notified as to any change in their reporting period.</P> <P>(4) Transportation allowances must be reported as a separate line item on Form MMS-4430, unless MMS approves a different reporting procedure.</P> <P>(d) <E T="03">Interest assessments for incorrect or late reports and failure to report.</E> (1) If a lessee deducts a transportation allowance on its Form MMS-4430 without complying with the requirements of this section, the lessee shall be liable for interest on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section.</P> <P>(2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment.</P> <P>(3) Interest required to be paid by this section shall be determined in accordance with 30 CFR 218.202.</P> <P>(e) <E T="03">Adjustments.</E> (1) If the actual transportation allowance is less than the amount the lessee has taken on Form MMS-4430 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest, computed pursuant to 30 CFR 218.202, retroactive to the first month the lessee is authorized to deduct a transportation allowance. If the actual transportation allowance is greater than the amount the lessee has estimated and taken during the reporting period, the lessee shall be entitled to a credit, without interest.</P> <P>(2) The lessee must submit a corrected Form MMS-4430 to reflect actual costs, together with any payment, <PRTPAGE P="162"/>in accordance with instructions provided by MMS.</P> <P>(f) <E T="03">Other transportation cost determinations.</E> The provisions of this section shall apply to determine transportation costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of transportation costs.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999; 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.462</SECTNO> <RESERVED>[Reserved]</RESERVED> </SECTION> <SECTION> <SECTNO>§ 206.463</SECTNO> <SUBJECT>In-situ and surface gasification and liquefaction operations.</SUBJECT> <P>If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to MMS. MMS will review the lessee's proposal and issue a value determination. The lessee may use its proposed value until MMS issues a value determination.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended at 64 FR 43289, Aug. 10, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 206.464</SECTNO> <SUBJECT>Value enhancement of marketable coal.</SUBJECT> <P>If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance with § 206.456(h) of this subpart, the lessee shall notify MMS that such processing is occurring or will occur. The value of that production shall be determined as follows:</P> <P>(a) A value established for the feedstock coal in marketable condition by application of the provisions of § 206.456(c)(2) (i) through (iv) of this subpart; or,</P> <P>(b) In the event that a value cannot be established in accordance with paragraph (a) of this section, then the value of production will be determined in accordance with § 206.456(c)(2)(v) of this subpart and the value shall be the lessee's gross proceeds accruing from the disposition of the enhanced product, reduced by MMS-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor's BBB bond rate applicable under § 206.458(b)(2)(v) of this subpart.</P> <CITA>[61 FR 5481, Feb. 12, 1996, as amended 64 FR 43289, Aug. 10, 1999]</CITA> </SECTION> </SUBPART> </PART> <PART> <EAR>Pt. 207</EAR> <HD SOURCE="HED">PART 207—SALES AGREEMENTS OR CONTRACTS GOVERNING THE DISPOSAL OF LEASE PRODUCTS</HD> <CONTENTS> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECHD>Sec.</SECHD> <SECTNO>207.1</SECTNO> <SUBJECT>Required recordkeeping.</SUBJECT> <SECTNO>207.2</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>207.3</SECTNO> <SUBJECT>Contracts made pursuant to new form leases.</SUBJECT> <SECTNO>207.4</SECTNO> <SUBJECT>Contracts made pursuant to old form leases.</SUBJECT> <SECTNO>207.5</SECTNO> <SUBJECT>Contract and sales agreement retention.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart B—Oil, Gas and OCS Sulfur, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart C—Federal and Indian Oil [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Federal and Indian Gas [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart F—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart H—Geothermal Resources [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>5 U.S.C. 301 <E T="03">et seq</E>.; 25 U.S.C. 396 <E T="03">et seq.</E>; 25 U.S.C. 396a <E T="03">et seq</E>.; 25 U.S.C. 2101 <E T="03">et seq.</E>; 30 U.S.C. 181 <E T="03">et seq.</E>; 30 U.S.C. 351 <E T="03">et seq.</E>; 30 U.S.C. 1001 <E T="03">et seq.</E>; 30 U.S.C. 1701 <E T="03">et seq.</E>; 31 U.S.C. 3716 <E T="03">et seq.</E>; 31 U.S.C. 9701; 43 U.S.C. 1301 <E T="03">et seq.</E>; 43 U.S.C. 1331 <E T="03">et seq.</E>; and 43 U.S.C. 1801 <E T="03">et seq.</E> </P> </AUTH> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>53 FR 1225, Jan. 15, 1988, unless otherwise noted.</P> </SOURCE> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECTION> <SECTNO>§ 207.1</SECTNO> <SUBJECT>Required recordkeeping.</SUBJECT> <P>(a) The information collection and recordkeeping requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 <E T="03">et seq.</E> and assigned OMB Clearance Number 1010-0061. The information collected will be <PRTPAGE P="163"/>used to determine a proper transportation allowance for the cost of transporting royalty oil from the lease to a delivery point remote from the lease. The information is required in order to obtain a benefit and is collected in accordance with the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 <E T="03">et seq.</E> </P> <P>(b) Public reporting burden is estimated to average 30 minutes per year for each record keeper to maintain copies of sales contracts, agreements, or other documents relevant to the valuation of production. Send any comments regarding this burden estimate or any other aspect of this requirement to the Information Collection Clearance Officer, Minerals Management Service, 381 Elden Street, Herndon, VA 22070, and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Paperwork Reduction Project 1010-0061, Washington, DC 20503.</P> <CITA>[57 FR 41864, Sept. 14, 1992, as amended at 58 FR 64901, Dec. 10, 1994]</CITA> </SECTION> <SECTION> <SECTNO>§ 207.2</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>The definitions in part 206 of this title are applicable to this part.</P> </SECTION> <SECTION> <SECTNO>§ 207.3</SECTNO> <SUBJECT>Contracts made pursuant to new form leases.</SUBJECT> <P>On November 29, 1950 (15 FR 8585), a new lease form was adopted (Form 4-1158, 15 FR 8585) containing provisions whereby the lessee agrees that nothing in any contract or other arrangement made for the sale or disposal of oil, gas, natural gasoline, and other products of the leased land, shall be construed as modifying any of the provisions of the lease, including, but not limited to, provisions relating to gas waste, taking royalty-in-kind, and the method of computing royalties due as based on a minimum valuation and in accordance with the oil and gas valuation regulations. A contract or agreement pursuant to a lease containing such provisions may be made without obtaining prior approval of the United States as lessor, but must be retained as provided in § 207.5 of this subpart.</P> </SECTION> <SECTION> <SECTNO>§ 207.4</SECTNO> <SUBJECT>Contracts made pursuant to old form leases.</SUBJECT> <P>(a) Old form leases are those containing provisions prohibiting sales or disposal of oil, gas, natural gasoline, and other products of the lease except in accordance with a contract or other arrangement approved by the Secretary of the Interior, or by the Director of the Minerals Management Service or his/her representative. A contract or agreement made pursuant to an old form lease may be made without obtaining approval if the contract or agreement contains either the substance of or is accompanied by the stipulation set forth in paragraph (b) of this section, signed by the seller (lessee or operator).</P> <P>(b) The stipulation, the substance of which must be included in the contract, or be made the subject matter of a separate instrument properly identifying the leases affected thereby, is as follows: </P> <EXTRACT> <P>It is hereby understood and agreed that nothing in the written contract or in any approval thereof shall be construed as affecting any of the relations between the United States and its lessee, particularly in matters of gas waste, taking royalty in kind, and the method of computing royalties due as based on a minimum valuation and in accordance with the terms and provisions of the oil and gas valuation regulations applicable to the lands covered by said contract.</P> </EXTRACT> </SECTION> <SECTION> <SECTNO>§ 207.5</SECTNO> <SUBJECT>Contract and sales agreement retention.</SUBJECT> <P>Copies of all sales contracts, posted price bulletins, etc., and copies of all agreements, other contracts, or other documents which are relevant to the valuation of production are to be maintained by the lessee and made available upon request during normal working hours to authorized MMS, State or Indian representatives, other MMS or BLM officials, auditors of the General Accounting Office, or other persons authorized to receive such documents, or shall be submitted to MMS within a reasonable period of time, as determined by MMS. Any oral sales arrangement negotiated by the lessee must be placed in written form and retained by the lessee. Records shall be retained in accordance with 30 CFR part 212.</P> </SECTION> </SUBPART> <SUBPART> <PRTPAGE P="164"/> <RESERVED>Subpart B—Oil, Gas, and OCS Sulfur, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart C—Federal and Indian Oil [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Federal and Indian Gas [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart F—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart H—Geothermal Resources [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> </PART> <PART> <EAR>Pt. 208</EAR> <HD SOURCE="HED">PART 208—SALE OF FEDERAL ROYALTY OIL</HD> <CONTENTS> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisons</HD> <SECHD>Sec.</SECHD> <SECTNO>208.1</SECTNO> <SUBJECT>General.</SUBJECT> <SECTNO>208.2</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>208.3</SECTNO> <SUBJECT>Information collection.</SUBJECT> <SECTNO>208.4</SECTNO> <SUBJECT>Royalty oil sales to eligible refiners.</SUBJECT> <SECTNO>208.5</SECTNO> <SUBJECT>Notice of royalty oil sale.</SUBJECT> <SECTNO>208.6</SECTNO> <SUBJECT>General application procedures.</SUBJECT> <SECTNO>208.7</SECTNO> <SUBJECT>Determination of eligibility.</SUBJECT> <SECTNO>208.8</SECTNO> <SUBJECT>Transportation and delivery.</SUBJECT> <SECTNO>208.9</SECTNO> <SUBJECT>Agreements.</SUBJECT> <SECTNO>208.10</SECTNO> <SUBJECT>Notices.</SUBJECT> <SECTNO>208.11</SECTNO> <SUBJECT>Surety requirements.</SUBJECT> <SECTNO>208.12</SECTNO> <SUBJECT>Payment requirements.</SUBJECT> <SECTNO>208.13</SECTNO> <SUBJECT>Reporting requirements.</SUBJECT> <SECTNO>208.14</SECTNO> <SUBJECT>Civil and criminal penalties.</SUBJECT> <SECTNO>208.15</SECTNO> <SUBJECT>Audits.</SUBJECT> <SECTNO>208.16</SECTNO> <SUBJECT>How to appeal a contracting officer's decision that you receive.</SUBJECT> <SECTNO>208.17</SECTNO> <SUBJECT>Suspensions for national emergencies.</SUBJECT> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>5 U.S.C. 301 <E T="03">et seq.</E>; 30 U.S.C. 181 <E T="03">et seq.,</E> 351 <E T="03">et seq.,</E> 1701 <E T="03">et seq.</E>; 31 U.S.C. 9701; 41 U.S.C. 601 <E T="03">et seq.</E>; 43 U.S.C. 1301 <E T="03">et seq.,</E> 1331 <E T="03">et seq.,</E> and 1801 <E T="03">et seq.</E> </P> </AUTH> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>52 FR 41913, Oct. 30, 1987, unless otherwise noted.</P> </SOURCE> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECTION> <SECTNO>§ 208.1</SECTNO> <SUBJECT>General.</SUBJECT> <P>The regulations in this part govern the sale of royalty oil by the United States to eligible refiners. The regulations apply to royalty oil from leases on Federal lands onshore and on the Outer Continental Shelf (OCS).</P> </SECTION> <SECTION> <SECTNO>§ 208.2</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P> <E T="03">Allotment</E> means the quantity of royalty oil that DOI determines is available to each eligible refiner that has applied for a portion of the total volume of royalty oil offered in a given royalty oil sale.</P> <P> <E T="03">Application</E> means the formal written request to DOI on Form MMS-4070 by an eligible refiner interested in purchasing a quantity of royalty oil from the approximate volume announced by DOI in a given “Notice of Availability of Royalty Oil.”</P> <P> <E T="03">Area</E> or <E T="03">Region</E> means the geographic territory having Federal oil and gas leases over which MMS has jurisdiction, unless the context in which those words are used indicates that a different meaning is intended.</P> <P> <E T="03">Contracting officer</E> means the Director, his or her delegate, or the person designated under a royalty oil purchase contract.</P> <P> <E T="03">Contracting officer's decision</E> means an MMS order or decision that a contracting officer issues under this part to a purchaser of oil under a royalty oil purchase contract.</P> <P> <E T="03">Delivery point</E> means the point where the lessor, in accordance with lease terms, directs the lessee to deliver royalty oil to a purchaser. Title to the royalty oil, or to the quantity thereof in a commingled stream, passes from the Federal Government to the purchaser at this designated point, which is specified in the royalty oil contract. For onshore leases, the delivery point will be on or adjacent to the lease, except as provided in § 208.8(a) of this part. In instances where an onshore delivery point is designated for offshore royalty oil, such point generally will be the first onshore point where the price of the oil, including transportation costs, can be determined and where the purchaser can either exchange or take delivery of the oil. The Government does not guarantee physical access to the oil at such point.</P> <P> <E T="03">Director</E> means the Director of MMS, who is responsible for its overall direction, or his or her delegate(s).<PRTPAGE P="165"/> </P> <P> <E T="03">DOI</E> means the Department of the Interior, including the Secretary or his or her delegate(s).</P> <P> <E T="03">Eligible refiner</E> means a refiner of crude oil that meets the following criteria for eligibility to purchase royalty oil:</P> <P>(1) For the purchase of royalty oil from onshore leases, it means a refiner that qualifies as a small and independent refiner as those terms are defined in sections 3(3) and 3(4) of the Emergency Petroleum Allocation Act, 15 U.S.C. 751 <E T="03">et seq.,</E> except that the time period for determination contained in section 3(3)(A) would be the calendar quarter immediately preceding the date of the applicable “Notice of Availability of Royalty Oil.” A refiner that, together with all persons controlled by, in control of, under common control with, or otherwise affiliated with the refiner, inputs a volume of domestic crude oil from its own production exceeding 30 percent of its total refinery input of crude oil is ineligible to participate in royalty oil sales under this part. Crude oil received in exchange for such refiner's own production is considered to be that refiner's own production for purposes of this section.</P> <P>(2) For the purchase of royalty oil from leases on the OCS, it means a refiner that qualifies as a small business enterprise under the rules of the Small Business Administration (13 CFR part 121).</P> <P> <E T="03">Entitlement</E> means the volume of royalty oil from the Federal Government's share of production from a Federal lease which a purchaser is entitled to receive under a royalty oil contract.</P> <P> <E T="03">Exchange agreement</E> means a written agreement between the purchaser and another person for the exchange of royalty oil purchased under this part for other oil on a volume or equivalent value basis.</P> <P> <E T="03">Fair market value</E> means the value of oil—(1) Computed at a unit price equivalent to the average unit price at which oil was sold pursuant to a lease during the period for which any royalty or net profit share is accrued or reserved to the United States pursuant to such lease, or</P> <P>(2) If there were no such sales, or if the Secretary finds that there were an insufficient number of such sales to equitably determine such value, computed at the average unit price at which oil was sold pursuant to other leases in the same region of the OCS during such period, or</P> <P>(3) If there were no sales of oil from such region during such period, or if the Secretary finds that there are an insufficient number of such sales to equitably determine such value, at an appropriate price determined by the Secretary.</P> <P> <E T="03">Federal lease</E> means a contractual agreement with the Federal Government which authorizes the exploration, development, and production of oil and gas on Federal lands onshore or on the OCS.</P> <P> <E T="03">Interim sale</E> means a sale conducted as a result of substantial additional royalty oil becoming available in a specific area prior to the scheduled expiration date of royalty oil contracts in effect for that area.</P> <P> <E T="03">Lessee</E> means any person to whom the United States issues a lease, or any person who has been assigned an obligation to make royalty or other payments required by the lease.</P> <P> <E T="03">MMS</E> means the Minerals Management Service of the Department of the Interior.</P> <P> <E T="03">Notice of Availability of Royalty Oil</E> means a notice published by DOI in the <E T="04">Federal Register</E> (and in other printed media when appropriate, such as a newspaper or magazine of general or specialized circulation) to advise interested parties of the availability of royalty oil for purchase by eligible refiners and the approximate volume of royalty oil available to the applicants.</P> <P> <E T="03">OCS</E> means the Outer Continental Shelf, as defined in 43 U.S.C. 1331(a).</P> <P> <E T="03">OCSLA</E> means the Outer Continental Shelf Lands Act (43 U.S.C. 1331 <E T="03">et seq.,</E> as amended by 43 U.S.C. 1801 <E T="03">et seq.</E>).</P> <P> <E T="03">Oil</E> means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities and is marketed or used as such. Condensate recovered in lease separators or field facilities is considered to be oil.</P> <P> <E T="03">Operator</E> means any person, including a lessee, who has control of or who <PRTPAGE P="166"/>manages operations on an oil and gas lease site on Federal onshore lands or on the OCS.</P> <P> <E T="03">Payor</E> means any person responsible for reporting royalties from a Federal lease or leases on Form MMS-2014.</P> <P> <E T="03">Person</E> means any individual, firm, corporation, association, partnership, consortium, or joint venture.</P> <P> <E T="03">Preference eligible refiner</E> means an eligible refiner with at least one operating refinery which is located within the area designated as the preference eligible area in the “Notice of Availability of Royalty Oil.” A refiner may be deemed to be a preference eligible refiner if it owns a refinery located in the preference eligible area which is not operational if the refiner meets the requirements of § 208.7(g) of this part.</P> <P> <E T="03">Purchaser</E> means anyone who acquires royalty oil sold by DOI under the Federal Government's Royalty-in-Kind (RIK) Program and who has a contractual obligation under an agreement to purchase royalty oil.</P> <P> <E T="03">Reallocation</E> means an offering of royalty oil previously allocated in a specific sale but subsequently turned back to MMS. A reallocation would only be made if substantial amounts of royalty oil are turned back.</P> <P> <E T="03">Refined petroleum product</E> means gasoline, kerosene, distillates (including Number 2 fuel oil), refined lubricating oils, or diesel fuel.</P> <P> <E T="03">Royalty oil</E> means that amount of oil that DOI takes in kind in partial or full satisfaction of a lessee's royalty or net profit share obligations as determined by whatever lease interest the lessee holds under an applicable mineral leasing law.</P> <P> <E T="03">Secretary</E> means the Secretary of the Department of the Interior or his/her delegate(s).</P> <P> <E T="03">Section 6 lease</E> means an oil and gas lease originally issued by any State and currently maintained in effect pursuant to section 6 of the OCSLA.</P> <P> <E T="03">Section 8 lease</E> means an oil and gas lease originally issued by the United States pursuant to section 8 of the OCSLA.</P> <CITA>[52 FR 41913, Oct. 30, 1987; 52 FR 45528, Nov. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993; 64 FR 26251, May 13, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.3</SECTNO> <SUBJECT>Information collection.</SUBJECT> <P>The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 <E T="03">et seq.</E> The form, filing date, and approved OMB clearance number are identified in 30 CFR 210.10.</P> <CITA>[58 FR 64901, Dec. 10, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.4</SECTNO> <SUBJECT>Royalty oil sales to eligible refiners.</SUBJECT> <P>(a) <E T="03">Determination to take royalty oil in kind.</E> The Secretary may evaluate crude oil market conditions from time to time. The evaluation will include, among other things, the availability of crude oil and the crude oil requirements of the Federal Government, primarily those requirements concerning matters of national interest and defense. The Secretary will review these items and will determine whether eligible refiners have access to adequate supplies of crude oil and whether such oil is available to eligible refiners at equitable prices. Such determinations may be made on a regional basis. The determination by the Secretary shall be published in the <E T="04">Federal Register</E> concurrent with or included in the “Notice of Availability of Royalty Oil” required by 30 CFR 208.5.</P> <P>(b) <E T="03">Sale to eligible refiners.</E> (1) Upon a determination by the Secretary under paragraph (a) of this section that eligible refiners do not have access to adequate supplies of crude oil at equitable prices, the Secretary, at his or her discretion, may elect to take in kind some or all of the royalty oil accruing to the United States from oil and gas leases on Federal lands onshore and on the OCS. The Secretary may authorize MMS to offer royalty oil for sale to eligible refiners only for use in their refineries and not for resale (other than under an exchange agreement).</P> <P>(2) All sales of royalty oil from onshore leases will be priced at the royalty value that would have been determined for that oil pursuant to 30 CFR part 206 had the royalties been paid in value rather than taken in kind. All sales of royalty oil from OCS leases will be priced at the fair market value of the oil including associated transportation costs to the designated delivery point, if applicable.<PRTPAGE P="167"/> </P> <P>(3) An eligible refiner must have a representative at a sale in order to participate. The Secretary may, at his or her discretion, establish purchase limitations and withhold any royalty oil from any offering.</P> <P>(c) Upon a determination by the Secretary under paragraph (a) of this section that eligible refiners do have access to adequate supplies of crude oil at equitable prices, MMS will not take royalties in kind from oil and gas leases for exclusive sale to such refiners. Such determinations may be made on a regional basis.</P> <P>(d) <E T="03">Interim sales.</E> The MMS generally will not conduct interim sales. However, interim sales may be held at the discretion of the Secretary if substantial addition royalty oil becomes available. The potentially eligible refiners, individually or collectively, must submit documentation demonstrating that adequate supplies of crude oil at equitable prices are not available for purchase. Although sufficient documentation must be submitted, it is not mandatory for each potentially eligible refiner to participate in a submission of such documentation to be determined eligible. The documentation must be submitted to MMS for a determination as to whether an interim sale is needed.</P> <CITA>[52 FR 41913, Oct. 30, 1987, as amended at 66 FR 28657, May 24, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.5</SECTNO> <SUBJECT>Notice of royalty oil sale.</SUBJECT> <P>If the Secretary decides to take royalty oil in kind for sale to eligible refiners, MMS will issue a “Notice of Availability of Royalty Oil” specifying the manner in which the sale is to be effected, the approximate quantity of royalty oil to be offered, information required in applications, the closing date for the receipt of applications for royalty oil, and other general administrative details concerning the application, allocation, and contract award process for the royalty oil. The Notice will describe generally the terms under which the royalty oil contracts will be awarded and will specify which applicants will be deemed preference eligible refiners in the sale proceedings. The Notice will also contain guidelines for reallocation procedures in the event substantial quantities of royalty oil sold in that specific sale are subsequently turned back to MMS. Only those purchasers that hold ongoing contracts from that specific sale will be allowed to participate in any reallocation, which would be voluntary, and then only if they continue to meet eligibility requirements as set forth in 30 CFR 208.2 and 208.7. If a reallocation is held prior to the effective date of the contracts as specified in the “Notice of Availability of Royalty Oil”, all eligible refiners that selected a lease or leases in that specific sale would be allowed to participate, pursuant to the procedures in the Notice.</P> </SECTION> <SECTION> <SECTNO>§ 208.6</SECTNO> <SUBJECT>General application procedures.</SUBJECT> <P>(a) To apply for the purchase of royalty oil, an applicant must file a Form MMS-4070 with MMS in accordance with instructions provided in the “Notice of Availability of Royalty Oil” and in accordance with any instructions issued by MMS for completion of Form MMS-4070. The applicant will be required to submit a letter of intent from a qualified financial institution stating that it would be granted surety coverage for the royalty oil for which it is applying, or other such proof of surety coverage, as deemed acceptable by MMS. The letter of intent must be submitted with a completed Form MMS-4070.</P> <P>(b) In addition to any other application requirements specified in the Notice, the following information is required on Form MMS-4070 at the time of application:</P> <P>(1) Name and address of the applicant, the location of the applicant's refinery or refineries, and disclosure of the applicant's affiliation with any other persons.</P> <P>(2) The capacity of the applicant's refineries in barrels of crude oil throughput per calendar day and a tabulation for the past 12 months of oil processed for each refinery, identified as to source (from own production or from other sources).</P> <P>(3) Identification of any Government royalty oil contracts under which the applicant is currently receiving royalty oil.<PRTPAGE P="168"/> </P> <P>(4) Identification of the locations (area/region and State) where the applicant proposes to purchase royalty oil, the volume of oil requested, and the specific refineries in which the oil will be refined.</P> <P>(5) A certification from the applicant that it is an eligible refiner for the purchase of Government royalty oil, as defined in § 208.2 of this part.</P> <CITA>[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.7</SECTNO> <SUBJECT>Determination of eligibility.</SUBJECT> <P>(a) The MMS will examine each application and may request additional information if the information in the application is inadequate. An application received after the close of the application period will be rejected. If additional information is requested by MMS, it must be received by the time specified or the application will be rejected.</P> <P>(b) After the close of the application period and the receipt of any additional requested information, MMS will determine which applicants may participate in the royalty oil sale and the quantity of royalty oil which each applicant is authorized to purchase.</P> <P>(c) When applications are filed by two or more eligible refiners for the same royalty oil, the oil will be allocated among such applicants on an equitable basis as determined by MMS. Preference eligible refiners will be given priority in the allocation procedures in sales and subsequent reallocations of royalty oil.</P> <P>(d) No eligible refiner shall be awarded contracts for volumes of royalty oil that, when added to volumes of other Federal royalty oil being received, are in excess of 60 percent of the combined refinery capacity of that refiner.</P> <P>(e) The MMS may exclude any section 6 lease from a royalty oil sale.</P> <P>(f) If two or more eligible refiners are related through common ownership or control or otherwise affiliated, only one of them shall be entitled to an allotment of royalty oil from a specific sale.</P> <P>(g) Any applicant whose refinery is not in operation during the 60-day period prior to the date of the royalty oil sale shall not be entitled to participate in the sale unless such applicant self-certifies and demonstrates to the satisfaction of MMS that it will begin operations by the first month in which oil becomes available under a royalty oil contract. If operations do not begin by that month, MMS will terminate the contract.</P> <P>(h) Applicants or purchasers that have delinquent balances with MMS as of the date of a royalty oil sale or subsequent reallocation will not be allowed to participate in that sale or reallocation. If a person which is controlled by, in control of, under common control with, or otherwise affiliated with an applicant or purchaser has such delinquent balances, the applicant or purchaser will not be allowed to participate in a royalty oil sale or reallocation. To the extent a purchaser or affiliated person has appealed a billing and posted a surety instrument in accordance with the contract terms and applicable MMS regulations or other law, the balance shall not be considered delinquent.</P> <P>(i) A purchaser must meet the eligibility criteria on the date of contract issuance. However, a change in a purchaser's eligibility status during the term of the contract will not affect the purchaser's right to continue that contract until its term expires, including any extensions thereof.</P> <CITA>[52 FR 41913, Oct. 30, 1987, as amended at 58 FR 64901, Dec. 10, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.8</SECTNO> <SUBJECT>Transportation and delivery.</SUBJECT> <P>(a) The lessee shall deliver royalty oil from onshore leases to the purchaser at a point on or adjacent to the lease pursuant to the terms of the lease. If the purchaser does not have access to its onshore royalty oil entitlement at facilities on or adjacent to the lease, the operator of the lease must designate an alternate delivery point at no additional cost to the purchaser or the Government. The purchaser must have physical access to the oil at the alternate delivery point and such point must be approved by MMS.</P> <P>(b) The lessee shall deliver royalty oil from section 8 offshore leases issued after September 1969 at a delivery point to be designated by MMS. The lessee shall deliver royalty oil from section 8 offshore leases issued before <PRTPAGE P="169"/>October 1969 or from section 6 leases at a delivery point to be designated by the lessee. If the delivery point is on or immediately adjacent to the lease, the royalty oil will be delivered without cost to the Federal Government as an undivided portion of production in marketable condition at pipeline connections or other facilities provided by the lessee, unless other arrangements are approved by MMS. If the delivery point is not on or immediately adjacent to the lease, MMS will reimburse the lessee for the reasonable cost of transportation to such point in an amount not to exceed the transportation allowance determined pursuant to 30 CFR part 206. The MMS will include such transportation costs in the price charged for the oil taken in kind to reflect the value of the oil at the delivery point. Arrangements for delivery of the royalty oil from, or exchange of the oil at, the delivery point, and related transportation costs, are the responsibility of the purchaser of the royalty oil. In addition, quality differentials between the royalty oil to which a purchaser is entitled and the oil which is made available at the delivery point are matters to be resolved between the purchaser and the operator.</P> <P>(c) When the purchaser has physical access to the royalty oil at the delivery point, the lessee shall deliver such oil in marketable condition at pipeline connections or other facilities designated by MMS. If the lessee is unable to provide the royalty portion of actual production from the lease, the lessee must provide crude oil to the purchaser which is equivalent in volume or value to the royalty oil to which the purchaser is entitled. The lessee will deliver the royalty oil to the purchaser during normal operating hours and in reasonable quantities and intervals. The lessee will make available and the purchaser will accept delivery of the royalty oil entitlement no later than the last day of the calendar month immediately following the calendar month in which the oil was produced. Failure to accept deliveries shall constitute grounds for the termination of the contract.</P> <P>(d) Upon termination of deliveries under a royalty oil contract, the transportation allowance and delivery point designation authorized by this section no longer will remain in effect.</P> </SECTION> <SECTION> <SECTNO>§ 208.9</SECTNO> <SUBJECT>Agreements.</SUBJECT> <P>(a) A purchaser must submit to MMS two copies of any written third-party agreements, or two copies of a full written explanation of any oral third-party agreements, relating to the method and costs of delivery of royalty oil, or crude oil exchanged for the royalty oil, from the point of delivery under the contract to the purchaser's refinery. In addition, the purchaser must submit copies of agreements pertaining to quality differentials which may occur between leases and delivery points.</P> <P>(b) A purchaser may not sell royalty oil which it purchases pursuant to this part except for purposes of an exchange for other crude oil on a volume or equivalent value basis.</P> <P>(c) Royalty oil purchased under this part, or crude oil received in exchange for such royalty oil, must be processed into refined petroleum products in the purchaser's refinery.</P> </SECTION> <SECTION> <SECTNO>§ 208.10</SECTNO> <SUBJECT>Notices.</SUBJECT> <P>(a) The MMS shall notify each operator, by certified mail, of the Secretary's decision to take royalty oil in kind. This notice shall be mailed at least 45 days in advance of the effective date of delivery and will specify delivery points for offshore oil for OCS leases issued after September 1969.</P> <P>(b) Deliveries of royalty oil may be partially terminated only with the written approval of the Director, MMS.</P> <P>(c) Before terminating the delivery of royalty oil taken in kind, MMS, if possible, will notify each operator by certified mail of the change in requirements at least 30 days in advance of the effective date.</P> <P>(d) After MMS notification that royalty oil will be taken in kind, the operator shall be responsible for notifying each working interest on the Federal lease. As soon as practicable after the date of each royalty oil sale, MMS will publish in the <E T="04">Federal Register</E> a notice of the leases from which royalty oil will be taken, the purchasers of the royalty oil, and the leases from which <PRTPAGE P="170"/>royalty oil deliveries will be discontinued on terminated contracts.</P> <P>(e) A purchaser cannot transfer, assign, or sell its rights or interest in a royalty oil contract without written approval of the Director, MMS. If the purchaser changes ownership or its assets are sold or liquidated for any reason, it cannot transfer, assign, or sell its rights or interest in the royalty oil contract without written approval of the Director, MMS. Without express written consent from MMS for a change in ownership, the royalty oil contract shall be terminated. The successor company must meet the definition of an eligible refiner in § 208.2 of this part for MMS to consider assignment of the royalty oil contract.</P> </SECTION> <SECTION> <SECTNO>§ 208.11</SECTNO> <SUBJECT>Surety requirements.</SUBJECT> <P>(a) The eligible purchaser, prior to execution of the contract, shall furnish an “MMS-specified surety instrument,” in an amount equal to the estimated value of royalty oil that could be taken by the purchaser in a 99-day period, plus related administrative charges. The MMS may require the purchaser to increase the amount of the surety instrument when necessary to protect the Government's interest or may allow the purchaser to decrease the amount of the surety instrument where necessary to further the purposes of the Royalty-in-Kind Program.</P> <P>(b) If a letter of credit is furnished as the surety instrument, it must be effective for a 9-month period beginning the first day the royalty oil contract is effective, with a clause providing for automatic renewal monthly for a new 9-month period. The purchaser or its surety company may elect not to renew the letter of credit at any monthly anniversary date, but must notify MMS of its intent not to renew at least 30 days prior to the anniversary date. The MMS may grant the purchaser 45 days to obtain a new surety instrument. If no replacement surety instrument is provided, MMS will terminate the contract effective at least 6 months prior to the expiration date of the letter of credit. Notwithstanding the above provisions, the letter of credit also may contain a clause providing for automatic termination 6 months after the royalty oil contract terminates. If a certificate of deposit is furnished as the surety instrument, it must be effective for the life of the contract plus 6 months after the royalty oil contract terminates.</P> <P>(c) For the purposes of this section, an “MMS-specified surety instrument” means either: an MMS-specified surety bond, an MMS-specified irrevocable letter of credit, or a financial institution book-entry certificate of deposit.</P> <P>(d) The “MMS-specified surety instrument” shall be in a form specified by MMS instructions or approved by MMS. A bond must be issued by a qualified surety company that has been approved by the Department of the Treasury. An irrevocable letter of credit or a certificate of deposit must be from a financial institution acceptable to MMS. The MMS will use a bank rating service to determine whether a financial institution has an acceptable rating to provide a surety instrument deemed adequate to indemnify the Government from loss or damage.</P> <P>(e) All surety instruments must be in a form acceptable to MMS and must include such other specific requirements as MMS may require adequately to protect the Government's interests.</P> <CITA>[58 FR 64901, Dec. 10, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.12</SECTNO> <SUBJECT>Payment requirements.</SUBJECT> <P>(a) All payments to MMS by a purchaser of royalty oil will be due on the date and at the location specified in the contract, or, if there is no contractual provision, as specified by MMS. The purchaser shall tender all payments to MMS in accordance with 30 CFR 218.51. Payments made by a payor pursuant to the requirements of paragraph (b) of this section and § 208.13 also shall be tendered in accordance with 30 CFR 218.51.</P> <P>(b)(1) Payments from a purchaser of royalty oil not received by MMS when due, or that portion of the payment less than the full amount due, will be subject to a late payment charge equivalent to an interest assessment on the amount past due for the number of days that the payment is late at the underpayment rate applicable under section 6621 of the Internal Revenue Code of 1954.</P> <P>(2) The MMS may assess interest to a payor for any underpayments which <PRTPAGE P="171"/>are the result of the payor's late or underreporting, or for adjustments reported by the payor, or made as a result of audit, reconciliation, or other procedures. The interest for late payment and underpayment will be assessed pursuant to 30 CFR 218.54.</P> <P>(c) If payment for royalty oil is not received by the due date specified in the contract, a notice of nonreceipt will be sent to the purchaser by certified mail. If payment is not received by MMS within 15 days from the date of such notice, MMS may cancel the contract and collect under the MMS-specified surety instrument. See § 208.11.</P> <P>(d) If the purchaser disagrees with the amount of payment due, it must pay the amount due as computed by MMS, unless the purchaser appeals the amount and posts an MMS-specified surety instrument pursuant to the provisions of 30 CFR part 243. The MMS may, at its discretion, waive the appeal surety requirements if it determines that the contract surety instrument is sufficient protection for an amount under appeal.</P> <CITA>[52 FR 41913, Oct. 30, 1987, as amended at 64901, Dec. 10, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.13</SECTNO> <SUBJECT>Reporting requirements.</SUBJECT> <P>If MMS underbills a purchaser under a royalty oil contract because of a payor's underreporting or failure to report on Form MMS-2014 pursuant to 30 CFR 210.52, the payor will be liable for payment of such underbilled amounts plus interest if they are unrecoverable from the purchaser or the surety instrument related to the contract.</P> <CITA>[58 FR 64902, Dec. 10, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.14</SECTNO> <SUBJECT>Civil and criminal penalties.</SUBJECT> <P>Failure to abide by the regulations in this part may result in civil and criminal penalties being levied on that person as specified in sections 109 and 110 of the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1719-20, and regulations at 30 CFR part 241. Civil penalties applicable under the OCSLA and the Mineral Leasing Act of 1920 may also be imposed.</P> </SECTION> <SECTION> <SECTNO>§ 208.15</SECTNO> <SUBJECT>Audits.</SUBJECT> <P>Audits of the accounts and books of lessees, operators, payors, and/or purchasers of royalty oil taken in kind may be made annually or at such other times as may be directed by MMS. Such audits will be for the purpose of determining compliance with applicable statutes, regulations, and royalty oil contracts.</P> </SECTION> <SECTION> <SECTNO>§ 208.16</SECTNO> <SUBJECT>How to appeal a contracting officer's decision that you receive.</SUBJECT> <P>If you receive a contracting officer's decision, you may:</P> <P>(a) Appeal that decision to the Board of Contract Appeals in the Office of Hearings and Appeals, Office of the Secretary, in accordance with the procedures provided in 43 CFR part 4, subpart C; or</P> <P>(b) File an action in the United States Court of Federal Claims.</P> <CITA>[64 FR 26251, May 13, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 208.17</SECTNO> <SUBJECT>Suspensions for national emergencies.</SUBJECT> <P>The Secretary of the Department of the Interior, upon a recommendation by the Secretary of Defense or the Secretary of Energy and with the approval of the President, may suspend operations under these regulations and suspend royalty oil contracts during a national emergency declared by the Congress or the President.</P> </SECTION> </SUBPART> </PART> <PART> <EAR>Pt. 210</EAR> <HD SOURCE="HED">PART 210—FORMS AND REPORTS</HD> <CONTENTS> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECHD>Sec.</SECHD> <SECTNO>210.10</SECTNO> <SUBJECT>Information collection.</SUBJECT> <SECTNO>210.20</SECTNO> <SUBJECT>When is electronic reporting required?</SUBJECT> <SECTNO>210.21</SECTNO> <SUBJECT>How do you report electronically?</SUBJECT> <SECTNO>210.22</SECTNO> <SUBJECT>What are the exceptions to the electronic reporting requirements?</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil, Gas, and OCS Sulfur—General</HD> <SECTNO>210.50</SECTNO> <SUBJECT>Required recordkeeping.</SUBJECT> <SECTNO>210.51</SECTNO> <SUBJECT>Payor information form.</SUBJECT> <SECTNO>210.52</SECTNO> <SUBJECT>Report of sales and royalty remittance.</SUBJECT> <SECTNO>210.53</SECTNO> <SUBJECT>Reporting instructions.</SUBJECT> <SECTNO>210.54</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>210.55</SECTNO> <SUBJECT>Special forms or reports.</SUBJECT> </SUBPART> <SUBPART> <PRTPAGE P="172"/> <RESERVED>Subpart C—Federal and Indian Oil [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Federal and Indian Gas [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Solid Minerals, General</HD> <SECTNO>210.200</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <SECTNO>210.201</SECTNO> <SUBJECT>How do I submit Form MMS-4430, Solid Minerals Production and Royalty Report?</SUBJECT> <SECTNO>210.202</SECTNO> <SUBJECT>How do I submit sales summaries?</SUBJECT> <SECTNO>210.203</SECTNO> <SUBJECT>How do I submit sales contracts?</SUBJECT> <SECTNO>210.204</SECTNO> <SUBJECT>How do I submit facility data?</SUBJECT> <SECTNO>210.205</SECTNO> <SUBJECT>Will I need to submit additional documents or evidence to MMS?</SUBJECT> <SECTNO>210.206</SECTNO> <SUBJECT>How will information submissions be kept confidential?</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart F—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Geothermal Resources</HD> <SECTNO>210.350</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>210.351</SECTNO> <SUBJECT>Required recordkeeping.</SUBJECT> <SECTNO>210.352</SECTNO> <SUBJECT>Special forms and reports.</SUBJECT> <SECTNO>210.353</SECTNO> <SUBJECT>Monthly report of sales and royalty.</SUBJECT> <SECTNO>210.354</SECTNO> <SUBJECT>Reporting instructions.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>5 U.S.C. 301 <E T="03">et seq.</E>; 25 U.S.C. 396, 2107; 30 U.S.C. 189, 190, 359, 1023, 1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 1334, 1801 <E T="03">et seq.</E>; and 44 U.S.C. 3506(a).</P> </AUTH> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECTION> <SECTNO>§ 210.10</SECTNO> <SUBJECT>Information collection.</SUBJECT> <P>(a) <E T="03">Forms</E>—This section identifies required MMS Minerals Revenue Management forms for reporting sales and royalties, production information, claiming a processing or transportation allowance, or claiming a reward for providing original information. The information collection requirements associated with the forms identified in this section have been approved by OMB under 44 U.S.C. 3501 <E T="03">et seq.</E> The forms, filing dates, and approved OMB clearance numbers are summarized below:</P> <GPOTABLE CDEF="s60,9" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">Form No., name, and filing date</CHED> <CHED H="1">OMB No.</CHED> </BOXHD> <ROW> <ENT I="01">MMS-2014—Report of Sales and Royalty Remittance—Due by the end of first month following production month for royalty payment and for rentals no later than anniversary date of the lease</ENT> <ENT>1010-0022</ENT> </ROW> <ROW> <ENT I="01">MMS-3160—Monthly Report of Operations—Due by the 15th day of the second month following the production month</ENT> <ENT>1010-0040</ENT> </ROW> <ROW> <ENT I="01">MMS-4025—Oil and Gas Payor Information Form—Due 30 days after issuance of a new lease or change to an existing lease</ENT> <ENT>1010-0033</ENT> </ROW> <ROW> <ENT I="01">MMS-4051—Facility and Measurement Information Form and Supplement—Due at the request of MMS during the initial conversion of the facility and measurement device operators</ENT> <ENT>1010-0040</ENT> </ROW> <ROW> <ENT I="01">MMS-4053—First Purchaser Report—Due at the request of MMS</ENT> <ENT>1010-0040</ENT> </ROW> <ROW> <ENT I="01">MMS-4054—Oil and Gas Operations Report—Due by the 15th day of the second month following the production month</ENT> <ENT>1010-0040</ENT> </ROW> <ROW> <ENT I="01">MMS-4055—Gas Analysis Report—Due by the 15th day of the second month following the production month</ENT> <ENT>1010-0040</ENT> </ROW> <ROW> <ENT I="01">MMS-4056—Gas Plant Operations Report—Due by the 15th day of the second month following the production month</ENT> <ENT>1010-0040</ENT> </ROW> <ROW> <ENT I="01">MMS-4058—Production Allocation Schedule Report—Due by the 15th day of the second month following the production month</ENT> <ENT>1010-0040</ENT> </ROW> <ROW> <ENT I="01">MMS-4070—Application of the Purchase of Royalty Oil—Due prior to the date of sale in accordance with the instructions in the Notice of Availability of Royalty Oil</ENT> <ENT>1010-0042</ENT> </ROW> <ROW> <ENT I="01">MMS-4109—Gas Processing Allowance Summary Report—Initial report due within 3 months following the last day of the month for which an allowance is first claimed, unless a longer period is approved by MMS</ENT> <ENT>1010-0075</ENT> </ROW> <ROW> <ENT I="01">MMS-4110—Oil Transportation Allowance Report—Initial report due within 3 months following the last day of the month for which an allowance is first claimed, unless a longer period is approved by MMS</ENT> <ENT>1010-0061</ENT> </ROW> <ROW> <ENT I="01">MMS-4280—Application for Reward for Original Information—Due when a reward is claimed for information provided which may lead to the recovery of royalty or other payments owed to the United States</ENT> <ENT>1010-0076</ENT> </ROW> <ROW> <ENT I="01">MMS-4292—Coal Washing Allowance Report—Due prior to or at the same time that the allowance is first reported on Form MMS-4430 and annually thereafter if the allowance does not change</ENT> <ENT>1010-0074</ENT> </ROW> <ROW> <ENT I="01">MMS-4293—Coal Transportation Allowance Report—Due prior to or at the same time that the allowance is first reported on Form MMS-4430 and annually thereafter if the allowance does not change</ENT> <ENT>1010-0074</ENT> </ROW> <ROW> <ENT I="01">MMS-4295—Gas Transportation Allowance Report—Initial report due within 3 months following the last day of month for which an allowance is first claimed unless a longer period is approved by MMS</ENT> <ENT>1010-0075</ENT> </ROW> <ROW> <ENT I="01">MMS-4377—Stripper Royalty Rate Reduction Notification—Due for each 12-month qualifying period that a reduced royalty rate is granted by the Bureau of Land Management</ENT> <ENT>1010-0090</ENT> </ROW> <ROW> <ENT I="01">MMS-4430—Solid Minerals Production and Royalty Report—Due by the end of the month following the month of production or sale and for other lease financial obligations no later than the payment date specified in your lease</ENT> <ENT>1010-0120</ENT> </ROW> <ROW> <ENT I="01">Facility Data—Due monthly or as requested for specific solid mineral products and lease types; see § 210.204</ENT> <ENT>1010-0120</ENT> </ROW> <ROW> <ENT I="01">Sales Contracts—Due semi-annually or as requested on certain solid mineral products and lease types; see § 210.203</ENT> <ENT>1010-0120</ENT> </ROW> <ROW> <PRTPAGE P="173"/> <ENT I="01">Sales Summaries—Due monthly or as requested for specific solid mineral products and lease types; see § 210.202</ENT> <ENT>1010-0120</ENT> </ROW> </GPOTABLE> <FP>The information required on the forms identified in the table above is being collected by the Department of the Interior to meet its congressionally mandated accounting and auditing responsibilities relating to Federal and Indian mineral royalty management. The purpose of the forms and the estimated public reporting burden associated with each form are described in paragraph (c) of this section. With the exception of Forms MMS-4109, MMS-4110, MMS-4280, MMS-4292, MMS-4293, and MMS-4295, the forms are mandatory. Information on Forms MMS-4109, MMS-4110, MMS-4292, MMS-4293, and MMS-4295 is required to receive a benefit. Information required on Form MMS-4280 must be provided voluntarily to claim a reward. Information collected relative to production, royalties, and other payments due the Government from activities on leased Federal or Indian land is authorized by the Federal Oil and Gas Royalty Management Act of 1982, 30 U.S.C. 1701 <E T="03">et seq.</E> for oil and gas production, and by 30 U.S.C. 189, 30 U.S.C. 359, and 30 U.S.C. 396d for solid mineral production.</FP> <P>(b) <E T="03">MMS mailing addresses</E>—This paragraph identifies the MMS address(es) to be used for requesting forms and/or for mailing completed forms to MMS.</P> <P>(1) Requests for Forms MMS-2014 or MMS-4070 should be addressed to the Minerals Management Service, Minerals Revenue Management, P.O. Box 5760, Denver, Colorado 80217-5760. The completed Form MMS-2014 should be mailed to the Minerals Management Service, Minerals Revenue Management, P.O. Box 5810, Denver, Colorado 80217-5810. The address to which a completed Form MMS-4070 should be mailed will be identified in a <E T="04">Federal Register</E> Notice of Availability of Royalty Oil. (See 30 CFR 208.5.)</P> <P>(2) Requests for Forms MMS-4025 should be addressed to the Minerals Management Service, Minerals Revenue Management, P.O. Box 5760, Denver, Colorado 80217-5760. The completed forms should be mailed to the same address.</P> <P>(3) Requests for Forms MMS-3160, MMS-4051, MMS-4052, MMS-4053, MMS-4054, MMS-4055, MMS-4056, MMS-4057, MMS-4058, or MMS-4061 should be addressed to the Minerals Management Service, Minerals Revenue Management, P.O. Box 17110, Denver, Colorado 80217-0110. The completed forms should be mailed to the same address.</P> <P>(4) Requests for processing or transportation allowance forms (Forms MMS-4109, MMS-4110, MMS-4292, MMS-4293, or MMS-4295) should be addressed to the Minerals Management Service, Minerals Revenue Management, P.O. Box 25165, Denver, Colorado 80225-0165. The completed allowance forms should be mailed to the Minerals Management Service, Minerals Revenue Management, P.O. Box 5200, Denver, Colorado 80217-5200.</P> <P>(5) Requests for Form MMS-4280 should be addressed to the Minerals Management Service, Minerals Revenue Management, P.O. Box 25165, Denver, Colorado 80225-0165. The completed form should be mailed to the same address. (See 30 CFR 218.57(b)).</P> <P>(6) If you are not reporting Form MMS-4430 electronically, you may request blank copies of the form by calling 1-888-201-6416. You must submit completed Forms MMS-4430 to the address given in § 210.201(c).</P> <P>(7) If you are not reporting solid minerals sales contracts, sales summaries, and facility data electronically, you must submit paper copies to the address given in § 210.202(c).</P> <P>(8) Reports for oil, gas, and geothermal leases sent by special courier or overnight mail (excluding U.S. Postal Service Express Mail) should be addressed to: Minerals Management Service, Minerals Revenue Management, Building 85, Room A-614, Denver Federal Center, Denver, Colorado 80225.</P> <P>(c) <E T="03">Purpose of forms and estimated public reporting burden</E>—This paragraph describes the purpose of the information being collected and the estimated public reporting burden associated with the OMB approved forms identified in paragraph (a) of this section.</P> <P>(1) <E T="03">MMS-2014</E>—Used monthly to report lease-related transactions essential for royalty management to determine the correct royalty amount due, reconcile or audit data, and distribute <PRTPAGE P="174"/>payments to appropriate accounts. Public reporting burden for paper submission is estimated to average 7 minutes to complete each line item on the form, including the time necessary to assemble data, calculate value and royalty, and enter data on the form. Companies reporting electronically may average 2 minutes to complete each line item on the form. Comments submitted relative to this information collection should reference the information collection titled Report of Sales and Royalty Remittance, OMB Control Number 1010-0022.</P> <P>(2) <E T="03">MMS-3160</E>—Used by onshore oil and gas lease operators to report monthly oil and gas production to MMS. Public reporting burden for paper submission is estimated to average 15 minutes per form, including the time necessary to assemble data, ensure that production and disposition numbers are accurate, and enter data on the form. Companies reporting electronically may average 7.5 minutes per month to complete the form. Comments submitted relative to this information collection should reference the information collection titled PAAS Oil and Gas Reports, OMB Control Number 1010-0040.</P> <P>(3) <E T="03">MMS-4025</E>—This form is used to establish a data base of payor accounts for oil and gas leases on Federal or Indian lands, reporting changes in payor accounts, and notifying MMS of the products on which royalties will be paid. Public reporting burden is estimated to average 30 minutes per form, including time spent reading instructions, completing, and mailing the form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0033.</P> <P>(4) <E T="03">MMS-4051</E>—Used to establish a reference data base identifying the facilities where oil and gas production is stored or processed and the metering points where production is measured for sale or transfer. Public reporting burden is estimated to average 30 minutes per form for facility operators to review and update the data base. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0040.</P> <P>(5) <E T="03">MMS-4053</E>—Designed as an audit tool to be used to confirm sales data. Public reporting burden is estimated to average 30 minutes per form, including time spent reading instructions, completing, and mailing the form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0040.</P> <P>(6) <E T="03">MMS-4054</E>—This three-part form identifies all oil and gas lease production from Federal and Indian lands. MMS uses information from this form to track oil and gas from the point of production to the point of first sale or other disposition. Respondents will generally not use all three parts of the form. Public reporting burden for paper submission is estimated to average 30 minutes per month, including the time necessary to assemble data, ensure that production and disposition numbers are accurate, and enter data on the form. Companies reporting electronically may average 15 minutes per month to complete the form. Comments submitted relative to this information collection should reference the information collection titled PAAS Oil and Gas Reports, OMB Control Number 1010-0040.</P> <P>(7) <E T="03">MMS-4055</E>—This report identifies the separate components of natural gas production. It is submitted quarterly or semiannually by lease operators when gas production is processed before royalty value has been determined. Public reporting burden is estimated to average 15 minutes per form including time required gathering data, completing, and mailing the form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0040.</P> <P>(8) <E T="03">MMS-4056</E>—Submitted monthly by gas plant operators to identify components and disposition of natural gas from Federal and Indian leases. Public reporting burden is estimated to average 30 minutes per form, including time required gathering data, completing, and mailing the form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0040.</P> <P>(9) <E T="03">MMS-4058</E>—Submitted monthly by operators of the facilities and measurement points where production from a Federal or Indian lease is commingled <PRTPAGE P="175"/>with production from other sources before it is measured for royalty determination. The data reported is used to determine whether sales reported by lessees are reasonable. Public reporting burden is estimated to average 15 minutes per form, including time required gathering data, completing, and mailing the form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0040.</P> <P>(10) <E T="03">MMS-4070</E>—After publication in the Federal Register of a Notice of Availability of Royalty Oil, refiners interested in the purchase of royalty oil should submit their applications using this form. The information collected is used by MMS to determine if the applicant meets eligibility requirements to contract to purchase the oil. Public reporting burden is estimated to average 1 hour per form, including time required gathering data, completing, and mailing the form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0042.</P> <P>(11) <E T="03">MMS-4109</E>—Used to claim an allowance for the reasonable, actual costs of removing hydrocarbon and nonhydrocarbon elements or compounds from the gas streams. Public reporting burden varies depending on the type of contract involved. Under an arm's-length contract, burden is estimated to average 1 hour for the submission of page 1 and schedule 1 of the form requiring the lessee's name and address, payor code, plant name, accounting identification number, product code, and selling arrangement. Nonarm's-length contract claims require completion of all pages of the form including calculations of allowable operating and maintenance costs, overhead, depreciation, and return on undepreciated capital investment. Public reporting burden is estimated to average 10 hours to complete the entire form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0075.</P> <P>(12) <E T="03">MMS-4110</E>—Used to claim an allowance for expenses incurred by a lessee in transporting oil from the lease site to a point remote from the lease where value is determined. Public reporting burden varies depending on the type of contract involved. Under an arm's-length contract, burden is estimated to average 2 hours for the submission of page 1 and schedule 1 of the form requiring the lessee's name and address, payor code, accounting identification number, product code, and selling arrangement. Nonarm's-length contract claims require completion of all pages of the form including calculations of allowable operating and maintenance costs, overhead, depreciation, and return on undepreciated capital investment. Public reporting burden is estimated to average 5 hours to complete the entire form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0061.</P> <P>(13) <E T="03">MMS-4280</E>—This form is used to claim a reward for information leading to the recovery of payments owed to the United States from oil and gas leases on Federal land or the Outer Continental Shelf. Claimants must provide name, address, Social Security number, and a brief description of the violation being reported. Public reporting burden is estimated to average 30 minutes to complete this form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0076.</P> <P>(14) <E T="03">MMS-4292</E>—This form is used to claim an allowance for the reasonable, actual costs incurred to wash coal. Public reporting burden varies depending on the type of contract involved. Under an arm's-length contract, burden is estimated to average 1 hour for the submission of page 1 of the form requiring the lessee's name and address, payor code, accounting identification number, product code, and selling arrangement. Nonarm's-length contract claims require completion of all pages of the form including calculations of allowable operating and maintenance costs, overhead, depreciation, and return on undepreciated capital investment. Public reporting burden is estimated to average 40 hours to complete the entire form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0074.</P> <P>(15) <E T="03">MMS-4293</E>—Used to claim an allowance for the reasonable, actual <PRTPAGE P="176"/>costs of transporting coal to a sales point or a washing facility remote from the mine or lease. Public reporting burden varies depending on the type of contract involved. Under an arm's-length contract, burden is estimated to average 1 hour for the submission of page 1 of the form requiring the lessee's name and address, payor code, accounting identification number, product code, and selling arrangement. Nonarm's-length contract claims require completion of all pages of the form including calculations of allowable operating and maintenance costs, overhead, depreciation, and return on undepreciated capital investment. Public reporting burden is estimated to average 40 hours to complete the entire form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0074.</P> <P>(16) <E T="03">MMS-4295</E>—This form is used to claim an allowance for the reasonable, actual costs of transporting gas from the lease to the point of first sale. Public reporting burden varies depending on the type of contract involved. Under an arm's-length contract, burden is estimated to average 1 hour for the submission of page 1 and schedule 1 of the form requiring the lessee's name and address, payor code, accounting identification number, product code, and selling arrangement. Nonarm's-length contract claims require completion of all pages of the form including calculations of allowable operating and maintenance costs, overhead, depreciation, and return on undepreciated capital investment. Public reporting burden is estimated to average 3 hours to complete the entire form. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0075.</P> <P>(17) <E T="03">MMS-4377</E>—This form must be submitted by operators of stripper oil properties to notify MMS of reduced royalty rates granted by the Bureau of Land Management under 43 CFR 3103.4-1 for each 12-month qualifying period. Reporting burden is estimated to require an average of 30 minutes per form to supply the operator name, lease and agreement numbers, calculated and current royalty rate, and the period covered. Comments submitted relative to this information collection should reference Paperwork Reduction Project 1010-0090.</P> <P>(18) <E T="03">MMS-4430</E>—Submitted monthly to report production from and royalty due on all Federal and Indian solid minerals leases (see § 210.201). MMS uses the data to distribute payments to appropriate recipients and to determine if lessees properly paid lease obligations. Public reporting burden is estimated to be 20 minutes per month per reporter. Comments relating to this information collection should reference OMB Control Number 1010-0120.</P> <P>(19) <E T="03">Facility data</E>—Submitted monthly by operators of wash plant, refining, ore concentration, or other processing facilities for specific solid minerals produced from specific Federal and Indian lease types or when otherwise requested by MMS (see § 210.204). MMS uses the data to assure that Federal or Indian lease processed production (the output of process plants) is consistent with the input of raw production. Public reporting burden is estimated to be approximately 15 minutes per reporter per month to compile in-house formatted information and submit that information electronically. Comments relating to this information collection should reference OMB Control Number 1010-0120.</P> <P>(20) <E T="03">Sales contracts</E>—Submitted semi-annually by producers of specific solid mineral products on specific Federal and Indian lease types or when otherwise requested by MMS (see § 210.203). MMS uses contracts, agreements and contract amendments for compliance purposes including, but not limited to, identifying valuation issues and establishing selling arrangement relationships. Public reporting burden is estimated to be 2 hours per reporter per year to compile and submit contracts and contract amendments. Comments relating to this information collection should reference OMB Control Number 1010-0120.</P> <P>(21) <E T="03">Sales summaries</E>—Submitted monthly by producers of specific solid minerals from specific Federal and Indian lease types or when otherwise requested by MMS (see § 210.202). The MMS uses these data for compliance purposes including, but not limited to, assuring that sales volumes and values <PRTPAGE P="177"/>are properly attributed or allocated to Federal or Indian leases. Public reporting burden is estimated to be 15 minutes per month for each reporter to compile in-house formatted sales information and submit that information electronically. Comments relating to this information collection should reference OMB Control Number 1010-0120.</P> <P>(d) <E T="03">Comments on burden estimates.</E> Send comments on the accuracy of this burden estimate or suggestions on reducing this burden to the Minerals Management Service, Attention: Information Collection Clearance Officer, (OMB Control Number 1010-0120 (insert appropriate OMB Control Number), Mail Stop 4230, 1849 C Street, NW., Washington, DC 20240. 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.</P> <CITA>[57 FR 41864, Sept. 14, 1992, as amended at 64 FR 38122, July 15, 1999; 66 FR 45769, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.20</SECTNO> <SUBJECT>When is electronic reporting required?</SUBJECT> <P>(a) You must submit Forms MMS-2014 and MMS-4054 to MMS electronically. You must begin reporting electronically according to the following timetable unless you qualify for the exceptions to electronic reporting listed in § 210.22:</P> <GPOTABLE CDEF="s50,r50" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">If you report the following number of lines each month on a required form . . .</CHED> <CHED H="1">Then, you must submit that form electronically beginning . . .</CHED> </BOXHD> <ROW> <ENT I="01">(1) 6 or more</ENT> <ENT>November 1, 1999.</ENT> </ROW> <ROW> <ENT I="01">(2) 4-5</ENT> <ENT>November 1, 2000.</ENT> </ROW> <ROW> <ENT I="01">(3) 1-3</ENT> <ENT>November 1, 2001.</ENT> </ROW> </GPOTABLE> <P>(b) See § 218.40(c) for the definition of a royalty report line on Form MMS-2014 and § 216.40(c) for the definition of a production report line on Form MMS-4054; and</P> <P>(c) For purposes of this part, multiple submissions of the same form in one month equals one form.</P> <CITA>[64 FR 38122, July 15, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.21</SECTNO> <SUBJECT>How do you report electronically?</SUBJECT> <P>(a) You may use any of the following electronic media types, unless MMS instructs you differently:</P> <P>(1) Electronic Data Interchange (EDI) <SU>1</SU> <FTREF/>—The inter-organizational, computer-to-computer exchange of structured information in a standard, machine-processable format;</P> <FTNT> <P> <SU>1</SU> MMS has developed security measures, authentication procedures, and automated acknowledgments for this electronic media type.</P> </FTNT> <P>(2) Electronic Mail (e-mail) <SU>1</SU>—Any communication service used to electronically transmit and store messages and attach files. MMS has three electronic file options:</P> <P>(i) Template—MMS-provided software that generates blank forms on a personal computer to assist companies in preparing MMS regulatory reports (this option is not available for Form MMS-4054);</P> <P>(ii) Comma Separated Values (CSV)—A file format where attribute fields are separated by commas; and</P> <P>(iii) American Standard Code for Information Interchange (ASCII)—A file format of fixed-length records with fixed-length attribute fields;</P> <P>(3) Reporter-Prepared Diskette (3<FR>1/2</FR> inch)—A data storage medium used to transmit report data using one of the following file formats:</P> <P>(i) Template;</P> <P>(ii) CSV; and</P> <P>(iii) ASCII;</P> <P>(4) Magnetic or Cartridge Tape—A data storage medium used to transmit report data in an ASCII file format.</P> <P>(b) MMS prefers that you use the media types in the order presented in paragraph (a) of this section to the extent it is cost effective and practical. As technology changes, MMS will consider other media types and the order of MMS preference may change. Refer to our electronic commerce brochure for the most current reporting options. You can receive a copy of our brochure by calling your MMS representative or by accessing our Internet site at <E T="03">www.rmp.mms.gov.</E> </P> <P>(c) Before you may begin reporting electronically:</P> <P>(1) You must submit an electronic sample of your report for MMS approval using the MMS-supplied electronic reporting guidelines;</P> <P>(2) MMS must notify you that your sample report has been approved;<PRTPAGE P="178"/> </P> <P>(3) MMS must assign you a sender identification number and security code for any EDI transmissions; and</P> <P>(4) MMS must assign you an originating address and compression software password for any e-mail transmissions.</P> <CITA>[64 FR 38123, July 15, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.22</SECTNO> <SUBJECT>What are the exceptions to the electronic reporting requirements?</SUBJECT> <P>MMS will allow the following grace periods and exceptions to the electronic reporting requirements in § 210.20:</P> <P>(a) If you become a new MMS reporter after any of the dates you are required to submit electronic reports under § 210.20(a), you have 3 months from the day your first report is due to begin reporting electronically;</P> <P>(b) If you exceed the maximum number of lines you are allowed to report on paper under § 210.20(a), you have 3 months from the last day of the month in which you exceeded the line limit to begin reporting electronically;</P> <P>(c) You are not required to report electronically if you report only rent, minimum royalty, or other annual obligations on the Form MMS-2014; and</P> <P>(d) You are not required to report electronically if you are a small business as defined by the U.S. Small Business Administration, and you have no computer, no resources to purchase a computer or contract with an electronic reporting service, nor access to a computer at a local library or other public facility.</P> <CITA>[64 FR 38123, July 15, 1999]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil, Gas, and OCS Sulfur—General</HD> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>The Federal Oil and Gas Royalty Management Act of 1982 (30 U.S.C. 1701 <E T="03">et seq.).</E> </P> </AUTH> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>49 FR 37345, Sept. 21, 1984, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 210.50</SECTNO> <SUBJECT>Required recordkeeping.</SUBJECT> <P>Information required by the MMS shall be filed using the forms prescribed in this subpart, which are available from MMS. Records may be maintained in microfilm, microfiche, or other recorded media that is easily reproducible and readable.</P> </SECTION> <SECTION> <SECTNO>§ 210.51</SECTNO> <SUBJECT>Payor information form.</SUBJECT> <P>The Payor Information Form (Form MMS-4025) must be filed for each Federal or Indian lease on which royalties are paid. Where specifically determined by MMS, Form MMS-4025 is also required for all Federal leases on which rent is due. The completed form must be filed by the party who is making the rent or royalty payment (payor) for each revenue source. Form MMS-4025 must be filed no later than 30 days after issuance of a new lease or a modification to an existing lease which changes the paying responsibility on the lease.</P> </SECTION> <SECTION> <SECTNO>§ 210.52</SECTNO> <SUBJECT>Report of sales and royalty remittance.</SUBJECT> <P>(a) You must submit a completed Form MMS-2014 (Report of Sales and Royalty Remittance) to MMS with:</P> <P>(1) All royalty payments; and,</P> <P>(2) Rents on nonproducing leases, where specified.</P> <P>(b) When you submit Form MMS-2014 data electronically, you must not submit the form itself.</P> <P>(c) Completed Forms MMS-2014 for royalty payments are due by the end of the month following the production month.</P> <P>(d) Where applicable, completed Forms MMS-2014 for rental payments are due no later than the anniversary date of the lease.</P> <P>(e) This section does not prohibit you from making early payments voluntarily.</P> <CITA>[64 FR 38123, July 15, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.53</SECTNO> <SUBJECT>Reporting instructions.</SUBJECT> <P>(a) Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in an MMS “Oil and Gas Payor Handbook,” a “Production Accounting and Auditing System Reporter Handbook,” and a “PAAS Onshore Oil and Gas Reporter Handbook.” The Payor Handbook is available from the Minerals Management Service, Royalty Management Program, P.O. Box 5760, Denver, Colorado 80217-5760. The Reporter Handbooks are available <PRTPAGE P="179"/>from the Minerals Management Service, Royalty Management Program, P.O. Box 17110, Denver, Colorado 80217-0110.</P> <P>(b) Royalty payors or production reporters should refer to these handbooks for specific guidance with respect to oil and gas reporting requirements. If additional information is required, the payor or reporter should contact the MMS at the above address. The appropriate telephone numbers are listed in the handbooks.</P> <CITA>[51 FR 45882, Dec. 23, 1986, as amended at 53 FR 16412, May 9, 1988; 57 FR 41867, Sept. 14, 1992; 58 FR 64902, Dec. 10, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.54</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.</P> <CITA>[49 FR 37345, Sept. 21, 1984. Redesignated at 51 FR 45882, Dec. 23, 1986]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.55</SECTNO> <SUBJECT>Special forms or reports.</SUBJECT> <P>(a) MMS may require you to submit additional information, forms, or reports other than those specifically referred to in this subpart. MMS will give you instructions for providing such information or filing such reports or forms. MMS will make requests for additional information, forms, or reports under this section in conformity with the Paperwork Reduction Act of 1995, 44 U.S.C. 3501, and other applicable laws.</P> <P>(b) If you file a Form MMS-4025, Payor Information Form (PIF) under § 210.51, you must provide the following information to MMS upon request for each PIF:</P> <P>(1) The AID number for the lease;</P> <P>(2) The name, address, Taxpayer Identification Number (TIN), and phone number of the person for whom you are reporting and paying royalties or making other payments under the PIF;</P> <P>(3) Whether the person you named in paragraph (b)(2) of this section with respect to the lease for which you filed the PIF is a:</P> <P>(i) Lessee of record (record title owner);</P> <P>(ii) Operating rights owner (working interest owner); or</P> <P>(iii) Operator;</P> <P>(4) The name, address, and phone number of the individual to contact for the person you named in paragraph (b)(2) of this section;</P> <P>(5) Your TIN; and</P> <P>(6) Whether you are the Designee of the person you named in paragraph (b)(2) of this section under 30 U.S.C. 1712(a), and, if so:</P> <P>(i) The date your designation became effective; and</P> <P>(ii) The date your designation terminates, if applicable; and</P> <P>(iii) A copy of the written designation;</P> <P>(c) If you have been identified under paragraph (b)(2) of this section, you must provide the following information to MMS upon request:</P> <P>(1) Confirmation that you are the person identified under paragraph (b)(2) of this section;</P> <P>(2) Confirmation that the person identified in paragraph (b)(6) of this section is your designee; and</P> <P>(3) A designation under § 218.52 of this title if the person identified in paragraph (b)(6) of this section is not your Designee, and if you are not reporting and paying royalties and making other payments to MMS.</P> <CITA>[62 FR 42066, Aug. 5, 1997]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart C—Federal and Indian Oil [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Federal and Indian Gas [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Solid Minerals, General</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>66 FR 45771, Aug. 30, 2001, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 210.200</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <P>This subpart explains your reporting requirements if you produce coal or other solid minerals from Federal or Indian leases. Included are your requirements for reporting production, sales, and royalties.</P> </SECTION> <SECTION> <SECTNO>§ 210.201</SECTNO> <SUBJECT>How do I submit Form MMS-4430, Solid Minerals Production and Royalty Report?</SUBJECT> <P>(a) <E T="03">What to submit.</E> (1) You must submit a completed Form MMS-4430 for—<PRTPAGE P="180"/> </P> <P>(i) Production of all coal and other solid minerals from any Federal or Indian lease;</P> <P>(ii) Sale of any such mineral;</P> <P>(iii) Any such mineral held in stockpile or inventory; and</P> <P>(iv) Payment of rents (other than those for which you receive from MMS a Courtesy Notice as defined in § 218.51(a) of this chapter), minimum royalty, deferred bonus, advance royalty, minimum royalty payable in advance, settlements, recoupments, and other financial obligations.</P> <P>(2) You must submit a completed Form MMS-4430 for any product you sell from a remote storage site. If you sell from five or fewer remote storage sites, you must report sales from each site on separate Forms MMS-4430. If you sell from more than five remote storage sites, you must total the data from all sites and report the summarized data on one Form MMS-4430.</P> <P>(3) Instructions for completing and submitting Form MMS-4430 are available on our Internet reporting web site or you may contact us toll free at 1-888-201-6416.</P> <P>(b) <E T="03">When to submit.</E> (1) Unless your lease terms specify a different frequency for royalty payments, you must submit your Form MMS-4430 on or before the end of the month following the month in which you produce any solid mineral, sell any solid mineral, or hold any solid mineral production in stockpile or inventory. However, if the last day of the month falls on a weekend or holiday, your Form MMS-4430 is due on the next business day.</P> <P>(2) If your lease terms specify a different frequency for royalty payment, then you must submit your Form MMS-4430 on or before the date on which you must pay royalty under the terms of the lease.</P> <P>(3) You must submit your Form MMS-4430 for payment of rents (other than those for which you receive from MMS a Courtesy Notice as defined in § 218.51(a) of this chapter), minimum royalty, deferred bonus, advance royalty, minimum royalty payable in advance, settlements, recoupments, and other financial obligations on or before the date on which you must pay those obligations under the terms of the lease.</P> <P>(4) If the information on a previously reported Form MMS-4430 is no longer correct, you must submit a revised Form MMS-4430 by the last day of the month in which you learn that the previously reported information is no longer correct, except when the last day of the month falls on a weekend or holiday. If the last day of the month falls on a weekend or holiday, your revised Form MMS-4430 is due on the first business day of the following month.</P> <P>(c) <E T="03">How to submit.</E> (1) You must submit Form MMS-4430 electronically using our Internet reporting web site unless you meet the conditions in paragraph (c)(2). We will provide written instructions and a valid login and password before you begin reporting.</P> <P>(2) You are not required to report electronically if you are a small business as defined by the U.S. Small Business Administration (13 CFR 121.201) and you have no computer, no plans to purchase a computer, and no contract with an electronic reporting service.</P> <P>(3) If you do not report electronically, you must submit the completed Form MMS-4430 to us at one of the following addresses, unless MMS publishes notice in the <E T="04">Federal Register</E> giving a different address:</P> <P>(i) <E T="03">For U.S. Postal Service regular mail or Express Mail:</E> Minerals Management Service, Minerals Revenue Management, P.O. Box 5810, Denver, Colorado 80217-5810; or</P> <P>(ii) <E T="03">For courier service or overnight mail (excluding Express Mail):</E> Minerals Management Service, Minerals Revenue Management, Building 85, Denver Federal Center, Room A-614, Denver, Colorado 80225.</P> <CITA>[66 FR 45771, Aug. 30, 2001; 66 FR 50827, Oct. 5, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.202</SECTNO> <SUBJECT>How do I submit sales summaries?</SUBJECT> <P>(a) <E T="03">What to submit.</E> (1) You must submit sales summaries for all coal and other solid minerals produced from Federal and Indian leases and for any remote storage site from which you sell Federal or Indian solid minerals. You do not have to submit a sales summary for those months in which you do not sell any Federal or Indian production.<PRTPAGE P="181"/> </P> <P>(2) If you sell from five or fewer remote storage sites, you must submit a sales summary for each site. If you sell from more than five remote storage sites, you may total the data from all sites and submit the summarized data as one sales summary. The details you report on the sales summary are for the same sales reported on Form MMS-4430.</P> <P>(3) Use the following table to determine the time frames for submitting sales summaries and the data elements you must include. Your submitted sales summaries must include the following data but may be internally generated documents from your own records. You do not need to re-format them before submitting them to us:</P> <GPOTABLE CDEF="s25,r13,r13,r13,r13,r13,xs40" COLS="7" OPTS="L2"> <BOXHD> <CHED H="1">Data element</CHED> <CHED H="1">Coal</CHED> <CHED H="1">Sodium/potassium</CHED> <CHED H="1">Western<LI>phosphate</LI> </CHED> <CHED H="1">Metals</CHED> <CHED H="1">All other leases with ad valorem royalty terms</CHED> <CHED H="1">All other leases with no ad valorem royalty terms</CHED> </BOXHD> <ROW> <ENT I="01">(i) Purchaser Name or Unique Identification</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>As Requested</ENT> </ROW> <ROW> <ENT I="01">(ii) Sales Units</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> </ROW> <ROW> <ENT I="01">(iii) Gross Proceeds</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(iv) Processing or washing costs</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(v) Transportation costs</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(vi) Name of product type sold</ENT> <ENT>Not Required</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Monthly</ENT> <ENT>Monthly</ENT> <ENT>As Requested</ENT> </ROW> <ROW> <ENT I="01">(vii) Btu/lb</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(viii) Ash %</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(ix) Sulfur %</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(x) lbs SO2</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(xi) Moisture %</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(xii) By-product Units</ENT> <ENT>Not Required</ENT> <ENT>As Requested</ENT> <ENT>Monthly</ENT> <ENT>As Requested</ENT> <ENT>As Requested</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(xiii) P2O5 %</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(xiv) Size</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>As Requested</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(xv) Net Smelter Return data</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> <ENT>Monthly</ENT> <ENT>Not Required</ENT> <ENT>Not Required</ENT> </ROW> <ROW> <ENT I="01">(xvi) Other Data e.g., Royalty Calculation Worksheet</ENT> <ENT>As Requested</ENT> <ENT>Monthly</ENT> <ENT>As Requested</ENT> <ENT>As Requested</ENT> <ENT>As Requested</ENT> <ENT>As Requested.</ENT> </ROW> </GPOTABLE> <P>(b) <E T="03">When to submit.</E> (1) For leases with ad valorem royalty terms (that is, leases for which royalty is a percentage of the value of production), you must submit your sales summaries monthly at the same time you submit Form MMS-4430. You do not have to submit a sales summary for any month in which you did not sell Federal or Indian production.</P> <P>(2) For leases with no ad valorem royalty terms (that is, leases in which the royalty due is not a function of the value of production, such as cents-per-ton or dollars-per-unit), you must submit monthly sales summaries only if we specifically request you to do so.</P> <P>(c) <E T="03">How to submit.</E> (1) You should provide the sales summary data via electronic mail where possible. We will provide instructions and the proper email address for these submissions.</P> <P>(2) If you submit sales summaries by paper copy, mail them to one of the following addresses, unless MMS publishes notice in the <E T="04">Federal Register</E> giving a different address:</P> <P>(i) <E T="03">For U.S. Postal Service regular mail or Express Mail:</E> Minerals Management Service, Minerals Revenue Management, Solid Minerals and Geothermal Compliance and Asset Management, P.O. Box 25165, MS 390G1, Denver, Colorado 80225-0165.</P> <P>(ii) <E T="03">For courier service or overnight mail (excluding Express Mail):</E> Minerals Management Service, Solid Minerals and Geothermal Compliance and Asset Management, 12600 West Colfax Avenue, Suite C-100, Lakewood, Colorado 80215.</P> </SECTION> <SECTION> <SECTNO>§ 210.203</SECTNO> <SUBJECT>How do I submit sales contracts?</SUBJECT> <P>(a) <E T="03">What to submit.</E> You must submit sales contracts, agreements, and contract amendments for the sale of all coal and other solid minerals produced <PRTPAGE P="182"/>from Federal and Indian leases with ad valorem royalty terms.</P> <P>(b) <E T="03">When to submit.</E> (1) For coal and metal production, you must submit the required documents semi-annually, no later than March 30 and September 30 of each year.</P> <P>(2) For sodium, potassium, and phosphate production, and production from any other lease with ad valorem royalty terms, you must submit the required documents only if you are specifically requested to do so.</P> <P>(c) <E T="03">How to submit.</E> You must submit complete copies of the sales contracts and amendments to us at the applicable address given in § 210.202(c)(2), unless MMS publishes notice in the <E T="04">Federal Register</E> giving a different address.</P> </SECTION> <SECTION> <SECTNO>§ 210.204</SECTNO> <SUBJECT>How do I submit facility data?</SUBJECT> <P>(a) <E T="03">What to submit.</E> (1) You must submit facility data if you operate a wash plant, refining, ore concentration, or other processing facility for any coal, sodium, potassium, metals, or other solid minerals produced from Federal or Indian leases with ad valorem royalty terms, regardless of whether the facility is located on or off the lease.</P> <P>(2) You do not have to submit facility data for those months in which you do not process solid minerals produced from Federal or Indian leases and do not have any such minerals in stockpile inventory.</P> <P>(3) You must include in your facility data all production processed in the facility from all properties, not just production from Federal and Indian leases.</P> <P>(4) Facility data submissions must include the following minimum information:</P> <P>(i) Identification of your facility;</P> <P>(ii) Mines served;</P> <P>(iii) Input quantity;</P> <P>(iv) Input quality or ore grade (except for coal);</P> <P>(v) Output quantity; and</P> <P>(vi) Output quality or product grades.</P> <P>(5) Your submitted facility data may be internally generated documents from your own records. You do not need to re-format them before submitting them to us.</P> <P>(b) <E T="03">When to submit.</E> You must submit your facility data monthly at the same time you submit your Form MMS-4430.</P> <P>(c) <E T="03">How to submit.</E> (1) You should provide the facility data via electronic mail where possible. We will provide instructions and the proper email address for these submissions before you begin reporting.</P> <P>(2) If you submit facility data by paper copy, send it to the applicable address given in § 210.202(c)(2).</P> </SECTION> <SECTION> <SECTNO>§ 210.205</SECTNO> <SUBJECT>Will I need to submit additional documents or evidence to MMS?</SUBJECT> <P>(a) Federal and Indian lease terms allow us to request detailed statements, documents, or other evidence necessary to verify compliance with lease terms and conditions and applicable rules.</P> <P>(b) We will request this additional information as we need it, not as a regular submission.</P> </SECTION> <SECTION> <SECTNO>§ 210.206</SECTNO> <SUBJECT>How will information submissions be kept confidential?</SUBJECT> <P>Information submitted under this part that constitutes trade secrets or commercial and financial information that is identified as privileged or confidential, or that is exempt from disclosure under the Freedom of Information Act, 5 U.S.C. 552, shall not be available for public inspection or made public or disclosed without the consent of the lessee, except as otherwise provided by law or regulation.</P> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart F—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Geothermal Resources</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>56 FR 57286, Nov. 8, 1991, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 210.350</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart shall have the same meaning as in 30 CFR 206.351.</P> </SECTION> <SECTION> <SECTNO>§ 210.351</SECTNO> <SUBJECT>Required recordkeeping.</SUBJECT> <P>Information required by MMS shall be filed using the forms prescribed in <PRTPAGE P="183"/>this subpart, which are available from MMS. Records may be maintained on microfilm, microfiche, or other recorded media that are easily reproducible and readable. See subpart H of 30 CFR part 212.</P> </SECTION> <SECTION> <SECTNO>§ 210.352</SECTNO> <SUBJECT>Special forms and reports.</SUBJECT> <P>The MMS may require submission of additional information on special forms or reports. When special forms or reports other than those referred to in this subpart are necessary, MMS will give instructions for the filing of such forms or reports. Requests for the submission of such forms will be made in conformity with the requirements of the Paperwork Reduction Act of 1980 and other applicable laws.</P> <CITA>[56 FR 57286, Nov. 8, 1991. Redesignated at 72 FR 24467, May 2, 2007]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.353</SECTNO> <SUBJECT>Monthly report of sales and royalty.</SUBJECT> <P>A completed Report of Sales and Royalty Remittance (Form MMS-2014) must be submitted each month once sales or utilization of production occur, even though sales may be intermittent, unless otherwise authorized by MMS. This report is due on or before the last day of the month following the month in which production was sold or utilized, together with the royalties due the United States.</P> <CITA>[56 FR 57286, Nov. 8, 1991. Redesignated at 72 FR 24467, May 2, 2007]</CITA> </SECTION> <SECTION> <SECTNO>§ 210.354</SECTNO> <SUBJECT>Reporting instructions.</SUBJECT> <P>Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in the publication titled <E T="03">Minerals Revenue Reporter Handbook—Oil, Gas, and Geothermal Resources,</E> which is available from the Minerals Management Service, Minerals Revenue Management, Financial Management, P.O. Box 25165, Mail Stop 350B1, Denver, CO 80225-0165. For copies from the MMS Web site, go to <E T="03">http://www.mrm.mms.gov/.</E> Click Reporting Information and select the topic.</P> <CITA>[72 FR 24467, May 2, 2007]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> </PART> <PART> <EAR>Pt. 212</EAR> <HD SOURCE="HED">PART 212—RECORDS AND FILES MAINTENANCE</HD> <CONTENTS> <SUBPART> <RESERVED>Subpart A—General Provisions [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil, Gas, and OCS Sulphur—General</HD> <SECHD>Sec.</SECHD> <SECTNO>212.50</SECTNO> <SUBJECT>Required recordkeeping and reports.</SUBJECT> <SECTNO>212.51</SECTNO> <SUBJECT>Records and files maintenance.</SUBJECT> <SECTNO>212.52</SECTNO> <SUBJECT>Definitions.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart C—Federal and Indian Oil [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Federal and Indian Gas [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Solid Minerals—General</HD> <SECTNO>212.200</SECTNO> <SUBJECT>Maintenance of and access to records.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart F—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Geothermal Resources</HD> <SECTNO>212.350</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>212.351</SECTNO> <SUBJECT>Required recordkeeping and reports.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>5 U.S.C. 301 <E T="03">et seq.</E>; 25 U.S.C. 396 <E T="03">et seq.,</E> 396a <E T="03">et seq.,</E> 2101 <E T="03">et seq.</E>; 30 U.S.C. 181 <E T="03">et seq.,</E> 351 <E T="03">et seq.,</E> 1001 <E T="03">et seq.,</E> 1701 <E T="03">et seq.</E>; 31 U.S.C. 9701; 43 U.S.C. 1301 <E T="03">et seq.,</E> 1331 <E T="03">et seq.,</E> and 1801 <E T="03">et seq.</E> </P> </AUTH> <SUBPART> <RESERVED>Subpart A—General Provisions [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil, Gas, and OCS Sulphur—General</HD> <SECTION> <SECTNO>§ 212.50</SECTNO> <SUBJECT>Required recordkeeping and reports.</SUBJECT> <P>All records pertaining to offshore and onshore Federal and Indian oil and gas leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the recordholder is notified, in writing, that records must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the recordholder is released by <PRTPAGE P="184"/>written notice of the obligation to maintain records.</P> <CITA>[49 FR 37345, Sept. 21, 1984]</CITA> </SECTION> <SECTION> <SECTNO>§ 212.51</SECTNO> <SUBJECT>Records and files maintenance.</SUBJECT> <P>(a) <E T="03">Records.</E> Each lessee, operator, revenue payor, or other person shall make and retain accurate and complete records necessary to demonstrate that payments of rentals, royalties, net profit shares, and other payments related to offshore and onshore Federal and Indian oil and gas leases are in compliance with lease terms, regulations, and orders. Records covered by this section include those specified by lease terms, notices and orders, and by the various parts of this chapter. Records also include computer programs, automated files, and supporting systems documentation used to produce automated reports or magnetic tape submitted to the Minerals Management Service (MMS).</P> <P>(b) <E T="03">Period for keeping records.</E> Lessees, operators, revenue payors, or other persons required to keep records under this section shall maintain and preserve them for 6 years from the day on which the relevant transaction recorded occurred unless the Secretary notifies the record holder of an audit or investigation involving the records and that they must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the recordholder is released in writing from the obligation to maintain the records. Lessees, operators, revenue payors, or other persons shall maintain the records generated during the period for which they have paying or operating responsibility on the lease for a period of 6 years.</P> <P>(c) <E T="03">Inspection of records.</E> The lessee, operator, revenue payor, or other person required to keep records shall be responsible for making the records available for inspection. Records shall be provided at a business location of the lessee, operator, revenue payor, or other person during normal business hours upon the request of any officer, employee or other party authorized by the Secretary. Lessees, operators, revenue payors, and other persons will be given a reasonable period of time to produce historical records.</P> <CITA>[49 FR 37345, Sept. 21, 1984; 49 FR 40576, Oct. 17, 1984, as amended at 67 FR 19111, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 212.52</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.</P> <CITA>[49 FR 37345, Sept. 21, 1984]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart C—Federal and Indian Oil [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Federal and Indian Gas [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals—General</RESERVED> <SECTION> <SECTNO>§ 212.200</SECTNO> <SUBJECT>Maintenance of and access to records.</SUBJECT> <P>(a) All records pertaining to Federal and Indian solid minerals leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the record holder is notified, in writing, that records must be maintained for a longer period. When an audit or investigation is underway, records shall be maintained until the record holder is released by written notice of the obligation to maintain records.</P> <P>(b) The MMS shall have access to all records of the operator/lessee pertaining to compliance to Federal royalties, including, but not limited to:</P> <P>(1) Qualities and quantities of all products mined, processed, sold, delivered, or used by the operator/lessee.</P> <P>(2) Prices received for mined or processed products, prices paid for like or similar products, and internal transfer prices.</P> <P>(3) Costs of mining, processing, handling, and transportation.</P> <CITA>[47 FR 33193, July 30, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 51 FR 15767, Apr. 28, 1986; 54 FR 1532, Jan. 13, 1989]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart F—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <PRTPAGE P="185"/> <HD SOURCE="HED">Subpart H—Geothermal Resources</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>56 FR 57286, Nov. 8, 1991, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 212.350</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart shall have the same meaning as in 30 CFR 206.351.</P> </SECTION> <SECTION> <SECTNO>§ 212.351</SECTNO> <SUBJECT>Required recordkeeping and reports.</SUBJECT> <P>(a) <E T="03">Records.</E> Each lessee, operator, revenue payor, or other person shall make and retain accurate and complete records necessary to demonstrate that payments of royalties, rentals, and other amounts due under Federal geothermal leases are in compliance with laws, lease terms, regulations, and orders. Records covered by this section include those specified by lease terms, notices, and orders, and those identified in paragraph (c) of this section. Records also include computer programs, automated files, and supporting systems documentation used to produce automated reports or magnetic tapes submitted to MMS.</P> <P>(b) <E T="03">Period for keeping records.</E> All records pertaining to Federal geothermal leases shall be maintained by a lessee, operator, revenue payor, or other person for 6 years after the records are generated unless the recordholder is notified, in writing, before the expiration of that 6-year period that records must be maintained for a longer period for purposes of audit or investigation. When an audit or investigation is underway, records shall be maintained until the recordholder is released by written notice of the obligation to maintain records.</P> <P>(c) <E T="03">Access to records.</E> The Associate Director for Minerals Revenue Management shall have access to all records in the possession of the lessee, operator, revenue payor, or other person pertaining to compliance with royalty obligations under Federal geothermal leases (regardless of whether such records were generated more than 6 years before a request or order to produce them and they otherwise were not disposed of), including, but not limited to:</P> <P>(1) Qualities and quantities of all products extracted, processed, sold, delivered, or used by the operator/lessee;</P> <P>(2) Prices received for products, prices paid for like or similar products, and internal transfer prices; and</P> <P>(3) Costs of extraction, power generation, electrical transmission, and byproduct transportation.</P> <P>(d) <E T="03">Inspection of Records.</E> The lessee, operator, revenue payor, or other person required to keep records shall be responsible for making the records available for inspection. Records shall be made available at a business location of the lessee, operator, revenue payor, or other person during normal business hours upon the request of any officer, employee, or other party authorized by the Secretary. Lessees, operators, revenue payors, and other persons will be given a reasonable period of time to produce records.</P> <CITA>[56 FR 57286, Nov. 8, 1991, as amended at 67 FR 19111, Apr. 18, 2002]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart I—OCS Sulfur [Reserved]</RESERVED> </SUBPART> </PART> <PART> <RESERVED>PART 215—ACCOUNTING AND AUDITING STANDARDS [RESERVED]</RESERVED> </PART> <PART> <EAR>Pt. 216</EAR> <HD SOURCE="HED">PART 216—PRODUCTION ACCOUNTING</HD> <CONTENTS> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECHD>Sec.</SECHD> <SECTNO>216.1</SECTNO> <SUBJECT>Purpose.</SUBJECT> <SECTNO>216.2</SECTNO> <SUBJECT>Scope.</SUBJECT> <SECTNO>216.6</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>216.10</SECTNO> <SUBJECT>Information collection.</SUBJECT> <SECTNO>216.11</SECTNO> <SUBJECT>Electronic reporting.</SUBJECT> <SECTNO>216.15</SECTNO> <SUBJECT>Reporting instructions.</SUBJECT> <SECTNO>216.16</SECTNO> <SUBJECT>Where to report.</SUBJECT> <SECTNO>216.20</SECTNO> <SUBJECT>Applicability.</SUBJECT> <SECTNO>216.21</SECTNO> <SUBJECT>General obligations of the reporter.</SUBJECT> <SECTNO>216.25</SECTNO> <SUBJECT>Confidentiality.</SUBJECT> <SECTNO>216.30</SECTNO> <SUBJECT>Special forms and reports.</SUBJECT> <SECTNO>216.40</SECTNO> <SUBJECT>Assessments for incorrect or late reports and failure to report.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil and Gas, General</HD> <SECTNO>216.50</SECTNO> <SUBJECT>Monthly report of operations.</SUBJECT> <SECTNO>216.51</SECTNO> <SUBJECT>Facility and Measurement Information Form.</SUBJECT> <SECTNO>216.52</SECTNO> <SUBJECT>First Purchaser Report.</SUBJECT> <SECTNO>216.53</SECTNO> <SUBJECT>Oil and Gas Operations Report.</SUBJECT> <SECTNO>216.54</SECTNO> <SUBJECT>Gas Analysis Report.</SUBJECT> <SECTNO>216.55</SECTNO> <SUBJECT>Gas Plant Operations Report.</SUBJECT> <SECTNO>216.56</SECTNO> <SUBJECT>Production Allocation Schedule Report.<PRTPAGE P="186"/> </SUBJECT> <SECTNO>216.57</SECTNO> <SUBJECT>Stripper royalty rate reduction notification.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart C—Oil and Gas, Onshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Oil, Gas, and Sulphur, Offshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart F—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart H—Geothermal Resources [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart I—Indian Land [Reserved]</RESERVED> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>5 U.S.C. 301 <E T="03">et seq.</E>; 25 U.S.C. 396, 2107; 30 U.S.C. 189, 190, 359, 1023, 1751(a); 31 U.S.C. 3716, 9701; 43 U.S.C. 1334, 1801 <E T="03">et seq.</E>; and 44 U.S.C. 3506(a).</P> </AUTH> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>51 FR 8175, Mar. 7, 1986, unless otherwise noted.</P> </SOURCE> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECTION> <SECTNO>§ 216.1</SECTNO> <SUBJECT>Purpose.</SUBJECT> <P>The purpose of this part is to ensure that the Federal Government receives proper information regarding energy and mineral resources removed from Federal and Indian leases and federally approved agreements, including the Outer Continental Shelf (OCS).</P> </SECTION> <SECTION> <SECTNO>§ 216.2</SECTNO> <SUBJECT>Scope.</SUBJECT> <P>This part governs the reporting of oil or gas operations information on Federal and Indian leases or federally-approved agreements including leases or agreements on the OCS. This part also governs the reporting of other operational information associated with production from Federal and Indian leases or federally-approved agreements when such operations occur prior to the point of sale or royalty determination, whichever is applicable. Reporters are required to submit certain production reports to MMS as set forth in this part.</P> <CITA>[58 FR 45254, Aug. 27, 1993, as amended at 66 FR 45773, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.6</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>For purposes of this part:</P> <P> <E T="03">Agreement</E> means a binding arrangement between two or more parties purporting to the act of agreeing or of coming to a mutual arrangement that is accepted by all parties to a transaction (e.g., communitizations, unitization, gas storage, or compensatory royalty agreements.).</P> <P> <E T="03">Alaska Native Corporation</E> means a corporation created pursuant to the provisions of the Alaska Native Claims Settlement Act (43 U.S.C. 1601 <E T="03">et seq.</E>).</P> <P> <E T="03">Associate Director</E> means the Associate Director for Minerals Revenue Management of the MMS.</P> <P> <E T="03">Facility</E> means a structure(s) used to store or process Federal or Indian mineral production prior to or at the point of royalty determination.</P> <P> <E T="03">Federal lease</E> means a lease concerning minerals owned by the United States and includes a lease where an Alaska Native Corporation receives all or part of the royalties accruing from that lease, and the MMS has not waived administration of that lease.</P> <P> <E T="03">First purchaser</E> means any entity receiving the lease production in a first transfer for value transaction.</P> <P> <E T="03">Gas</E> means any fluid, either combustible or noncombustible, which is extracted from a reservoir and which has neither independent shape nor volume, but tends to expand indefinitely; a substance that exists in a gaseous or rarefied state under standard temperature and pressure conditions.</P> <P> <E T="03">Indian lease</E> means a lease concerning lands or interest in lands of an Indian Tribe or an Indian allottee, his heirs or devisees, held in trust by the United States or which is subject to Federal restriction against alienation, including mineral resources and mineral estates reserved to an Indian Tribe or an Indian allottee, his heirs or devisees thereto in the conveyance of a surface or non-mineral estate, except that such term does not include any lands subject to the provisions of section 3 of the Act of June 28, 1906 (34 Stat. 539).</P> <P> <E T="03">Lease</E> means any contract, profit-share arrangement, joint venture, permit, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, extraction of, or removal <PRTPAGE P="187"/>of oil or gas—or the land area covered by that authorization, whichever is covered by the context.</P> <P> <E T="03">Lessee</E> means any person to whom the United States, an Indian Tribe, or an Indian allottee, issues a lease, or any person who has been assigned an obligation to make royalty or other payments required by the lease.</P> <P> <E T="03">Measurement device</E> means a mechanical or electrical device that is used to measure production of oil or gas for sales, transfers, and/or royalty determination.</P> <P> <E T="03">Mineral leasing law</E> means any Federal law administered by the Secretary authorizing the disposition under lease of oil or gas.</P> <P> <E T="03">Oil</E> means any fluid hydrocarbon substance other than gas which is extracted in a fluid state from a reservoir and which exists in a fluid state under the existing temperature and pressure conditions of the reservoir. Oil includes liquefiable hydrocarbon substances such as drip gasoline or other natural condensates recovered in a liquid state from gas.</P> <P> <E T="03">Operator</E> means any person, including a lessee who has control of, or who manages operations on, any oil and gas lease site on Federal (including the OCS) or Indian lands. “Operator” also means any entity engaged in the business of developing, drilling for, producing, transporting, purchasing, selling, or processing oil or gas and/or which has the responsibility of reporting production from a lease or a portion thereof.</P> <P> <E T="03">Outer Continental Shelf (OCS)</E> has the same meaning as provided in section 2 of the Outer Continental Shelf Lands Act, 43 U.S.C. 1331.</P> <P> <E T="03">Person</E> means any individual, firm, corporation, association, partnership, consortium or joint venture.</P> <P> <E T="03">Raw make</E> means natural gas liquids (NGL's) that are extracted from the wet gas stream at a gas plant (e.g., ethane through natural gasoline) which sometimes is transferred to a fractionation plant for further processing.</P> <P> <E T="03">Reporter</E> means any reporting entity required to submit a production report or form to the MMS.</P> <P> <E T="03">Secretary</E> means the Secretary of the Interior or his/her designee.</P> <CITA>[51 FR 8175, Mar. 7, 1986, as amended at 58 FR 45254, Aug. 27, 1993; 66 FR 45773, Aug. 30, 2001; 67 FR 19111, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.10</SECTNO> <SUBJECT>Information collection.</SUBJECT> <P>The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 <E T="03">et seq.</E> The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10.</P> <CITA>[57 FR 41867, Sept. 14, 1992]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.11</SECTNO> <SUBJECT>Electronic reporting.</SUBJECT> <P>You must submit your Oil and Gas Operations Report, Form MMS-4054, in accordance with electronic reporting requirements in 30 CFR part 210.</P> <CITA>[64 FR 38123, July 15, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.15</SECTNO> <SUBJECT>Reporting instructions.</SUBJECT> <P>(a) Specific guidance on how to prepare and submit required information collection reports and forms to MMS is contained in the production reporter handbook. The production reporter handbook is available from the Minerals Management Service, Minerals Revenue Management, P.O. Box 17110, Denver, Colorado 80217-0110.</P> <P>(b) Production reporters should refer to the handbook for specific guidance with respect to production reporting requirements. If additional information is required, the reporter should contact the MMS at the above address. The telephone number is listed in the handbook.</P> <CITA>[53 FR 16412, May 9, 1988, as amended at 57 FR 41867, Sept. 14, 1992; 58 FR 64903, Dec. 10, 1993; 67 FR 19111, Apr. 18, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.16</SECTNO> <SUBJECT>Where to report.</SUBJECT> <P>(a) All reporting forms listed in this part that are mailed or sent by U.S. Postal Service express mail should be mailed to the Minerals Management Service, Minerals Revenue Management, P.O. Box 17110, Denver, Colorado 80217-0110.</P> <P>(b) Reports delivered to MMS by special couriers or overnight mail, except U.S. Postal Service express mail, shall be addressed as follows: Minerals Management Service, Minerals Revenue <PRTPAGE P="188"/>Management, Building 85, Denver Federal Center, Denver, Colorado 80225.</P> <P>(c) A report is considered received when it is delivered to MMS at the addresses specified in paragraphs (a) and (b) of this section. Reports received at the MMS addresses specified in paragraphs (a) and (b) of this section after 4 p.m. mountain time are considered received the following business day.</P> <CITA>[56 FR 20127, May 2, 1991, as amended at 57 FR 41867, Sept. 14, 1992; 58 FR 64903, Dec. 10, 1993; 67 FR 19111, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.20</SECTNO> <SUBJECT>Applicability.</SUBJECT> <P>The requirements of this part shall apply to all oil and gas operators reporting information on Federal and Indian leases or federally-approved agreements, including leases or agreements on the OCS.</P> <CITA>[58 FR 45254, Aug. 27, 1994, as amended at 66 FR 45773, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.21</SECTNO> <SUBJECT>General obligations of the reporter.</SUBJECT> <P>The reporter shall submit accurately, completely and timely, pursuant to the requirements of this part, all information forms and other information required by MMS. Specific guidance on the use of the required forms is contained in the production reporter handbook. Copies of the handbook are available from the MMS.</P> <CITA>[51 FR 8175, Mar. 7, 1986, as amended at 67 FR 19111, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.25</SECTNO> <SUBJECT>Confidentiality.</SUBJECT> <P>(a) Information obtained by MMS pursuant to the rules of this part shall be open for public inspection and copying during regular office hours upon a written request, pursuant to rules at 43 CFR part 2, except that:</P> <P>(1) Notwithstanding any other provision of this part, information obtained from a reporter under this part relating to a minerals agreement approved pursuant to the Indian Mineral Development Act of 1982, 25 U.S.C. 2101 <E T="03">et seq.,</E> the Tribal Leasing Act of 1938 (25 U.S.C. 396a <E T="03">et seq.</E>), or the Allotted Indian Mineral Development Act of 1909 (25 U.S.C. 396), shall not be released without the written consent of the Indian Tribe(s) or individual Indian(s) who are parties to the mineral agreement.</P> <P>(2) Information obtained from a reporter pursuant to this part that constitutes a trade secret and/or commercial or financial information which is privileged or confidential, or other information that may be withheld under the Freedom of Information Act (5 U.S.C. 552(b)), such as geologic and geophysical data concerning wells, shall be available for public inspection in accordance with 43 CFR part 2. When such information is related to Indian lands, consent to release the information must also be obtained from the cognizant Tribe or allottee.</P> <P>(b) If any geologic and/or geophysical data is submitted under this part, these shall be made available to the public only in accordance with the provisions of 30 CFR 250.3, 250.4 and 252.7, if these relate to an offshore lease, and in accordance with 43 CFR 3162.8 if these relate to an onshore Federal or Indian lease.</P> </SECTION> <SECTION> <SECTNO>§ 216.30</SECTNO> <SUBJECT>Special forms and reports.</SUBJECT> <P>When special forms or reports other than those referred to in the regulations in this part are necessary, instructions for the filing of such forms or reports will be provided by the Associate Director. Such requests will be made in conformity with the requirements of the Paperwork Reduction Act of 1995, and are expected to involve less than 10 respondents annually.</P> <CITA>[51 FR 8175, Mar. 7, 1986, as amended at 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.40</SECTNO> <SUBJECT>Assessments for incorrect or late reports and failure to report.</SUBJECT> <P>(a) An assessment of an amount not to exceed $10 per day may be charged for each report not received by MMS by the designated due date.</P> <P>(b) An assessment of an amount not to exceed $10 may be charged for each incorrectly completed report.</P> <P>(c) For purposes of oil and gas reporting under the PAAS, a report is defined as each line of production information required on the Monthly Report of Operations (Form MMS-3160), Oil and Gas Operations Report (Form MMS-4054), Gas Analysis Report (Form MMS-4055), Gas Plant Operations Report (Form <PRTPAGE P="189"/>MMS-4056), and Production Allocation Schedule Report (Form MMS-4058).</P> <P>(d) The MMS will not make assessments for reporting problems which are beyond the control of the reporter (e.g., reports received late because of bad weather). The reporter shall have the burden of proving that a reporting problem was unavoidable.</P> <P>(e) An assessment under this section shall not be shared with a State, Indian tribe, Indian allottee, or Alaska Native Corporation.</P> <P>(f) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by MMS. The assessment amount for each violation will be based on MMS's experience with costs and improper reporting. The MMS will publish a Notice of the assessment amount to be applied in the <E T="04">Federal Register.</E> </P> <CITA>[51 FR 8175, Mar. 7, 1986, as amended at 52 FR 27546, July 22, 1987; 53 FR 16412, May 9, 1988; 58 FR 64903, Dec. 10, 1993; 59 FR 38905, Aug. 1, 1994; 66 FR 45773, Aug. 30, 2001]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil and Gas, General</HD> <SECTION> <SECTNO>§ 216.50</SECTNO> <SUBJECT>Monthly report of operations.</SUBJECT> <P>(a) You must submit a Monthly Report of Operations, Form MMS-3160, if you operate either an onshore Federal or Indian lease or an onshore federally-approved agreement that contains one or more wells that are not permanently plugged and abandoned. You may submit Form MMS-3160 electronically.</P> <P>(b) You must submit a Form MMS-3160 for each well for each calendar month, beginning with the month in which you complete drilling, unless you have only test production from a drilling well or MMS tells you in writing to do otherwise.</P> <P>(c) MMS must receive your completed Form MMS-3160 according to the following table:</P> <GPOTABLE CDEF="s50,r50" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">If you submit your form . . .</CHED> <CHED H="1">We must receive it by . . .</CHED> </BOXHD> <ROW> <ENT I="01">(1) Electronically</ENT> <ENT>The 25th day of the second month following the month for which you are reporting.</ENT> </ROW> <ROW> <ENT I="01">(2) Other than electronically</ENT> <ENT>The 15th day of the second month following the month for which you are reporting.</ENT> </ROW> </GPOTABLE> <P>(d) You must continue reporting until either:</P> <P>(1) BLM approves all wells as permanently plugged or abandoned and you dispose of all inventory; or</P> <P>(2) The lease or agreement is terminated.</P> <P>(e) You are not required to submit Form MMS-3160 if:</P> <P>(1) You are authorized to submit an Oil and Gas Operations Report, Form MMS-4054, instead of a Form MMS-3160; or</P> <P>(2) You operate a gas storage agreement. You must report gas storage agreements to the appropriate BLM office.</P> <P>(f) Specific and detailed guidance on how to prepare and submit the required production data on the Form MMS-3160 are contained in the MMS <E T="03">PAAS Onshore Oil and Gas Reporter Handbook.</E>See § 216.15 of this part.</P> <P>(g)(1) Operators already reporting onshore lease production data to MMS in accordance with § 216.53 of this part on the effective date of this rule may request to change to the provisions of this section. Any request to change to the requirements of this section must be made by advance written notice to MMS and have MMS approval.</P> <P>(2) An operator who reports production data to MMS for offshore leases in accordance with § 216.53 of this part may request to report for its onshore leases in accordance with the requirements of that section. Any such request must be made by advance written notice to MMS and have MMS approval.</P> <P>(h)(1) Except where disclosure is required by law, information submitted on Form MMS-3160 that MMS classifies as confidential will be protected as such by both MMS and BLM for the period of 1 year. Operators must petition MMS for each lease or agreement to obtain a confidential classification and to extend the classification period beyond 1 year.</P> <P>(2) Except as provided by statute, information submitted on Form MMS-3160 in regard to Federal leases and Indian leases which are part of a unit containing non-Indian leases is not considered to be confidential.</P> <P>(3) Except where disclosure is required by law, all information submitted on Form MMS-3160 in regard to <PRTPAGE P="190"/>Indian leases, other than those included in paragraph (d)(2) of this section, will be considered to be confidential.</P> <P>(4) Except as provided in this subsection, all other information will be released.</P> <CITA>[53 FR 16412, May 9, 1988, as amended at 58 FR 45254, Aug. 27, 1993; 58 FR 64903, Dec. 10, 1993; 64 FR 38123, July 15, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.51</SECTNO> <SUBJECT>Facility and Measurement Information Form.</SUBJECT> <P>A Facility and Measurement Information Form (Form MMS-4051) must be filed for each facility or measurement device which handles production from any Federal or Indian lease, or federally-approved agreement, through the point of first sale or the point of royalty computation, whichever is later. The completed form must be filed by any operator (reporting production on a Form MMS-4054) of an onshore Facility Measurement Point (FMP) that handles production from any Federal or Indian lease or federally-approved agreement prior to, or at the point of royalty determination, or any operator who acquires an onshore FMP that is currently reporting to the PAAS. The report must be filed no later than 30 days after the establishment of a new facility or measurement device, or 30 days after a change is made to an existing facility or measurement device.</P> <CITA>[58 FR 45254, Aug. 27, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.52</SECTNO> <SUBJECT>First Purchaser Report.</SUBJECT> <P>The First Purchaser Report (Form MMS-4053) must be filed by first purchasers only upon the specific request of MMS.</P> <CITA>[51 FR 8175, Mar. 7, 1986. Redesignated at 58 FR 64903, Dec. 10, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.53</SECTNO> <SUBJECT>Oil and Gas Operations Report.</SUBJECT> <P>(a) You must file an Oil and Gas Operations Report, Form MMS-4054, if you operate one of the following that contains one or more wells that are not permanently plugged or abandoned:</P> <P>(1) An OCS lease or federally-approved agreement; or</P> <P>(2) An onshore Federal or Indian lease or federally-approved agreement for which you elected to report on a Form MMS-4054 instead of a Form MMS-3160.</P> <P>(b) You must submit a Form MMS-4054 for each well for each calendar month, beginning with the month in which you complete drilling, unless you have only test production from a drilling well or MMS tells you in writing to do otherwise.</P> <P>(c) MMS must receive your completed Form MMS-4054 according to the following table:</P> <GPOTABLE CDEF="s50,r50" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">If you submit your form . . .</CHED> <CHED H="1">We must receive it by . . .</CHED> </BOXHD> <ROW> <ENT I="01">(1) Electronically</ENT> <ENT>The 25th day of the second month following the month for which you are reporting.</ENT> </ROW> <ROW> <ENT I="01">(2) Other than electronically</ENT> <ENT>The 15th day of the second month following the month for which you are reporting.</ENT> </ROW> </GPOTABLE> <P>(d) You must continue reporting until either:</P> <P>(1) BLM or MMS approves all wells as permanently plugged or abandoned and you dispose of all inventory; or</P> <P>(2) The lease or agreement is terminated.</P> <P>(e)(1) Notwithstanding the provisions of paragraph (c) of this section and § 216.50, the due date for submittal of the Oil and Gas Operations Report (Form MMS-4054) or Monthly Report of Operations (Form MMS-3160) for the production months of July, August, and September 2005 for Federal offshore and onshore oil and gas leases by oil and gas lessees or operators who make the certification required under paragraph (e)(2) of this section is extended to December 15, 2005 (if you do not file electronically) or December 27, 2005 (if you file electronically).</P> <P>(2) The extended due dates in paragraph (e)(1) of this section will apply to Oil and Gas Operations Reports (Form MMS-4054) and Monthly Reports of Operations (Form MMS-3160) by any lessee or operator who certifies that a hurricane that struck the Gulf of Mexico coast of the United States in August or September 2005 disrupted the lessee's or operator's operations to the extent that it prevented the lessee or operator from submitting an accurate Form MMS-4054 or MMS-3160.</P> <P>(3) Paragraphs (e)(1) and (e)(2) of this section do not apply to Indian leases or <PRTPAGE P="191"/>to Federal leases for minerals other than oil and gas.</P> <P>(4) Certifications under paragraph (e)(2) of this section should be submitted either:</P> <P>(i) By mail to: Robert Prael, Financial Manager, Minerals Management Service, Minerals Revenue Management, P.O. Box 25165, MS 350B1, Denver, CO 80225-0165, or</P> <P>(ii) By e-mail to <E T="03">Robert.Prael@mms.gov</E>.</P> <P>(f)(1) A lessee or operator who submits a certification required under paragraph (e)(2) of this section may rely on the extended due dates prescribed in paragraph (e)(1) of this section unless and until MMS notifies the lessee or operator that MMS does not accept the certification.</P> <P>(2) If MMS notifies a lessee or operator that MMS does not accept the lessee's or operator's certification under paragraph (e)(2) of this section, the due date for the Oil and Gas Operations Report or Monthly Report of Operations will be the date specified in the notice.</P> <CITA>[64 FR 38124, July 15, 1999, as amended at 70 FR 56852, Sept. 29, 2005]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.54</SECTNO> <SUBJECT>Gas Analysis Report.</SUBJECT> <P>When requested by MMS, any operator must file a Gas Analysis Report (GAR) (Form MMS-4055) for each royalty or allocation meter. The form must contain accurate and detailed gas analysis information. This requirement applies to offshore, onshore, or Indian leases.</P> <P>(a) MMS may request a GAR when you sell gas, or transfer gas for processing, before the point of royalty computation.</P> <P>(b) When MMS first requests this report, the report is due within 30 days. If MMS requests subsequent reports, they will be due no later than 45 days after the end of the month covered by the report.</P> <CITA>[63 FR 26367, May 12, 1998]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.55</SECTNO> <SUBJECT>Gas Plant Operations Report.</SUBJECT> <P>(a) You must submit a Gas Plant Operations Report, Form MMS-4056, if you operate either:</P> <P>(1) A gas plant that processes gas originating from an OCS lease or federally-approved agreement before the point of final royalty determination; or</P> <P>(2) A gas plant that processes gas from an onshore Federal or Indian lease or federally-approved agreement before the point of final royalty determination, and MMS has asked you to submit a Form MMS-4056.</P> <P>(b) You must submit a Form MMS-4056 for each calendar month beginning with the month gas processing is initiated.</P> <P>(c) MMS must receive your completed Form MMS-4056 according to the following table:</P> <GPOTABLE CDEF="s50,r50" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">If you submit your Form MMS-4054 . . .</CHED> <CHED H="1">We must receive your Form MMS-4056 by . . .</CHED> </BOXHD> <ROW> <ENT I="01">(1) Electronically</ENT> <ENT>The 25th day of the second month following the month for which you are reporting.</ENT> </ROW> <ROW> <ENT I="01">(2) Other than electronically</ENT> <ENT>The 15th day of the second month following the month for which you are reporting.</ENT> </ROW> </GPOTABLE> <P>(d) Your report must show 100 percent of the gas.</P> <P>(e) You are not required to file a Form MMS-4056 if:</P> <P>(1) Your plant has not processed gas that originated from a Federal onshore, OCS, or Indian lease, or federally-approved agreement before the point of final royalty determination for 6 months; and</P> <P>(2) You notified MMS in writing within 30 days after the end of the 6-month period.</P> <P>(f) You must file a Form MMS-4056 when your plant resumes processing gas that originated from a Federal onshore, OCS, or Indian lease, or federally-approved agreement before the point of final royalty determination.</P> <CITA>[64 FR 38124, July 15, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.56</SECTNO> <SUBJECT>Production Allocation Schedule Report.</SUBJECT> <P>(a) Any operator of an offshore Facility Measurement Point (FMP) handling production from a Federal lease or federally-approved agreement that is commingled (with approval) with production from any other source prior to measurement for royalty determination must file a Production Allocation Schedule Report (Form MMS-4058). This report is not required whenever all of the following conditions are met:<PRTPAGE P="192"/> </P> <P>(1) All leases involved are Federal leases;</P> <P>(2) All leases have the same fixed royalty rate;</P> <P>(3) All leases are operated by the same operator;</P> <P>(4) The facility measurement device is operated by the same person as the leases/agreements;</P> <P>(5) Production has not been previously measured for royalty determination; and</P> <P>(6) The production is not subsequently commingled and measured for royalty determination at an FMP for which Form MMS-4058 is required under this part.</P> <P>(b) You must submit a Production Allocation Schedule Report, Form MMS-4058, for each calendar month beginning with the month in which you first handle production covered by this section.</P> <P>(c) MMS must receive your Form MMS-4058 according to the following table:</P> <GPOTABLE CDEF="s50,r50" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">If you submit your Form MMS-4054 . . .</CHED> <CHED H="1">We must receive your Form MMS-4058 by . . .</CHED> </BOXHD> <ROW> <ENT I="01">(1) Electronically</ENT> <ENT>The 25th day of the second month following the month for which you are reporting.</ENT> </ROW> <ROW> <ENT I="01">(2) Other than electronically</ENT> <ENT>The 15th day of the second month following the month for which you are reporting.</ENT> </ROW> </GPOTABLE> <CITA>[58 FR 45255, Aug. 27, 1993. Redesignated at 58 FR 64903, Dec. 10, 1993, as amended at 64 FR 38124, July 15, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 216.57</SECTNO> <SUBJECT>Stripper royalty rate reduction notification.</SUBJECT> <P>In accordance with its regulations at 43 CFR 3103.4-1, titled “Waiver, suspension, or reduction of rental, royalty, or minimum royalty,” the Bureau of Land Management (BLM) may grant reduced royalty rates to operators of low producing oil leases to encourage continued production. Operators who have been granted a reduced royalty rate(s) by BLM must submit a Stripper Royalty Rate Reduction Notification (Form MMS-4377) to MMS for each 12-month qualifying period that a reduced royalty rate(s) is granted.</P> <CITA>[58 FR 64903, Dec. 10, 1993]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart C—Oil and Gas, Onshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Oil, Gas, and Sulfur, Offshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart E—Solid Minerals, General [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart F—Coal [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart G—Other Solid Minerals [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart H—Geothermal Resources [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart I—Indian Land [Reserved]</RESERVED> </SUBPART> </PART> <PART> <EAR>Pt. 217</EAR> <HD SOURCE="HED">PART 217—AUDITS AND INSPECTIONS</HD> <CONTENTS> <SUBPART> <RESERVED>Subpart A—General Provisions [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil and Gas, General</HD> <SECHD>Sec.</SECHD> <SECTNO>217.50</SECTNO> <SUBJECT>Audits of records.</SUBJECT> <SECTNO>217.51</SECTNO> <SUBJECT>Lease account reconciliation.</SUBJECT> <SECTNO>217.52</SECTNO> <SUBJECT>Definitions.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart C—Oil and Gas, Onshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Oil, Gas and Sulfur, Offshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Coal</HD> <SECTNO>217.200</SECTNO> <SUBJECT>Audits.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Other Solid Minerals</HD> <SECTNO>217.250</SECTNO> <SUBJECT>Audits.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart G—Geothermal Resources</HD> <SECTNO>217.300</SECTNO> <SUBJECT>Audits or review of records.</SUBJECT> <SECTNO>217.301</SECTNO> <SUBJECT>Lease account reconciliations.</SUBJECT> <SECTNO>217.302</SECTNO> <SUBJECT>Definitions.</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart H—Indian Lands [Reserved]</RESERVED> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>35 Stat. 312; 35 Stat. 781, as amended; secs. 32, 6, 26, 41 Stat. 450, 753, 1248; secs. 1, 2, 3, 44 Stat. 301, as amended; secs. 6, 3, 44 Stat. 659, 710; secs. 1, 2, 3, 44 Stat. 1057; 47 Stat. 1487; 49 Stat. 1482, 1250, 1967, 2026; 52 Stat. 347; sec. 10, 53 Stat. 1196, as amended; 56 Stat. 273; sec. 10, 61 Stat. 915; sec. 3, 63 Stat. 683; 64 Stat. 311; 25 U.S.C. 396, 396a-f, 30 U.S.C. 189, 271, 281, 293, 359. Interpret or apply secs. 5, 5, 44 Stat. 302, 1058, as amended; 58 Stat. 483-485; 5 U.S.C. 301, 16 U.S.C. 508b, 30 <PRTPAGE P="193"/>U.S.C. 189, 192c, 271, 281, 293, 359, 43 U.S.C. 387, unless otherwise noted.</P> </AUTH> <SUBPART> <RESERVED>Subpart A—General Provisions [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil and Gas, General</HD> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>The Federal Oil and Gas Royalty Management Act of 1982 (30 U.S.C. 1701 <E T="03">et seq.).</E> </P> </AUTH> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>49 FR 37345, Sept. 21, 1984, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 217.50</SECTNO> <SUBJECT>Audits of records.</SUBJECT> <P>The Secretary, or his/her authorized representative, shall initiate and conduct audits relating to the scope, nature and extent of compliance by lessees, operators, revenue payors, and other persons with rental, royalty, net profit share and other payment requirements on a Federal or Indian oil and gas lease. Audits also will relate to compliance with applicable regulations and orders. All audits will be conducted in accordance with the notice and other requirements of 30 U.S.C. 1717.</P> </SECTION> <SECTION> <SECTNO>§ 217.51</SECTNO> <SUBJECT>Lease account reconciliation.</SUBJECT> <P>Specific lease account reconciliations shall be performed with priority being given to reconciling those lease accounts specifically identified by a State or Indian tribe as having significant potential for underpayment.</P> </SECTION> <SECTION> <SECTNO>§ 217.52</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.</P> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart C—Oil and Gas, Onshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <RESERVED>Subpart D—Oil, Gas and Sulfur, Offshore [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Coal</HD> <SECTION> <SECTNO>§ 217.200</SECTNO> <SUBJECT>Audits.</SUBJECT> <P>An audit of the accounts and books of operators/lessees for the purpose of determining compliance with Federal lease terms relating to Federal royalties may be required annually or at other times as directed by the Associate Director for Minerals Revenue Management. The audit shall be performed by a qualified independent certified public accountant or by an independent public accountant licensed by a State, territory, or insular possession of the United States or the District of Columbia, and at the expense of the operator/lessee. The operator/lessee shall furnish, free of charge, duplicate copies of audit reports that express opinions on such compliance to the Associate Director for Minerals Revenue Management within 30 days after the completion of each audit. Where such audits are required, the Associate Director for Minerals Revenue Management will specify the purpose and scope of the audit and the information which is to be verified or obtained.</P> <CITA>[47 FR 33195, July 30, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, as amended at 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Other Solid Minerals</HD> <SECTION> <SECTNO>§ 217.250</SECTNO> <SUBJECT>Audits.</SUBJECT> <P>An audit of the lessee's accounts and books may be made annually or at such other times as may be directed by the mining supervisor, by certified public accountants, and at the expense of the lessee. The lessee shall furnish free of cost duplicate copies of such annual or other audits to the mining supervisor, within 30 days after the completion of each auditing.</P> <CITA>[37 FR 11041, June 1, 1972. Redesignated at 48 FR 35641, Aug. 5, 1983]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart G—Geothermal Resources</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>72 FR 24468, May 2, 2007, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 217.300</SECTNO> <SUBJECT>Audit or review of records.</SUBJECT> <P>The Secretary, or his/her authorized representative, will initiate and conduct audits or reviews relating to the scope, nature, and extent of compliance by lessees, operators, revenue payors, and other persons with rental, royalty, fees, and other payment requirements on a Federal geothermal lease. Audits or reviews will also relate to compliance with applicable regulations and orders. All audits or reviews will be conducted in accordance with this part.</P> </SECTION> <SECTION> <PRTPAGE P="194"/> <SECTNO>§ 217.301</SECTNO> <SUBJECT>Lease account reconciliations.</SUBJECT> <P>Specific lease account reconciliations will be performed with priority being given to reconciling those lease accounts specifically identified by a State as having significant potential for underpayment.</P> </SECTION> <SECTION> <SECTNO>§ 217.302</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart will have the same meaning as in 30 U.S.C. 1702.</P> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart H—Indian Lands [Reserved]</RESERVED> </SUBPART> </PART> <PART> <EAR>Pt. 218</EAR> <HD SOURCE="HED">PART 218—COLLECTION OF ROYALTIES, RENTALS, BONUSES AND OTHER MONIES DUE THE FEDERAL GOVERNMENT AND CREDITS AND INCENTIVES DUE LESSEES</HD> <CONTENTS> <SUBPART> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECHD>Sec.</SECHD> <SECTNO>218.10</SECTNO> <SUBJECT>Information collection.</SUBJECT> <SECTNO>218.40</SECTNO> <SUBJECT>Assessments for incorrect or late reports and failure to report.</SUBJECT> <SECTNO>218.41</SECTNO> <SUBJECT>Assessments for failure to submit payment of same amount as Form MMS-2014 or bill document or to provide adequate information.</SUBJECT> <SECTNO>218.42</SECTNO> <SUBJECT>Cross-lease netting in calculation of late-payment interest.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil and Gas, General</HD> <SECTNO>218.50</SECTNO> <SUBJECT>Timing of payment.</SUBJECT> <SECTNO>218.51</SECTNO> <SUBJECT>How to make payments.</SUBJECT> <SECTNO>218.52</SECTNO> <SUBJECT>How does a lessee designate a Designee?</SUBJECT> <SECTNO>218.53</SECTNO> <SUBJECT>Recoupment of overpayments on Indian mineral leases.</SUBJECT> <SECTNO>218.54</SECTNO> <SUBJECT>Late payments.</SUBJECT> <SECTNO>218.55</SECTNO> <SUBJECT>Interest payments to Indians.</SUBJECT> <SECTNO>218.56</SECTNO> <SUBJECT>Definitions.</SUBJECT> <SECTNO>218.57</SECTNO> <SUBJECT>Providing information and claiming rewards.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Oil and Gas, Onshore</HD> <SECTNO>218.100</SECTNO> <SUBJECT>Royalty and rental payments.</SUBJECT> <SECTNO>218.101</SECTNO> <SUBJECT>Royalty and rental remittance (naval petroleum reserves).</SUBJECT> <SECTNO>218.102</SECTNO> <SUBJECT>Late payment or underpayment charges.</SUBJECT> <SECTNO>218.103</SECTNO> <SUBJECT>Payments to States.</SUBJECT> <SECTNO>218.104</SECTNO> <SUBJECT>Exemption of States from certain interest and penalties.</SUBJECT> <SECTNO>218.105</SECTNO> <SUBJECT>Definitions.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart D—Oil, Gas and Sulfur, Offshore</HD> <SECTNO>218.150</SECTNO> <SUBJECT>Royalties, net profit shares, and rental payments.</SUBJECT> <SECTNO>218.151</SECTNO> <SUBJECT>Rental fees.</SUBJECT> <SECTNO>218.152</SECTNO> <SUBJECT>Fishermen's Contingency Fund.</SUBJECT> <SECTNO>218.153</SECTNO> <SUBJECT>[Reserved]</SUBJECT> <SECTNO>218.154</SECTNO> <SUBJECT>Effect of suspensions on royalty and rental.</SUBJECT> <SECTNO>218.155</SECTNO> <SUBJECT>Method of payment.</SUBJECT> <SECTNO>218.156</SECTNO> <SUBJECT>Definitions.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Solid Minerals—General</HD> <SECTNO>218.200</SECTNO> <SUBJECT>Payment of royalties, rentals, and deferred bonuses.</SUBJECT> <SECTNO>218.201</SECTNO> <SUBJECT>Method of payment.</SUBJECT> <SECTNO>218.202</SECTNO> <SUBJECT>Late payment or underpayment charges.</SUBJECT> <SECTNO>218.203</SECTNO> <SUBJECT>Recoupment of overpayments on Indian mineral leases.</SUBJECT> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Geothermal Resources</HD> <SECTNO>218.300</SECTNO> <SUBJECT>Payment of royalties, rentals, and deferred bonuses.</SUBJECT> <SECTNO>218.301</SECTNO> <SUBJECT>Method of payment.</SUBJECT> <SECTNO>218.302</SECTNO> <SUBJECT>Late payment or underpayment charges.</SUBJECT> <SECTNO>218.303</SECTNO> <SUBJECT>May I credit rental towards royalty?</SUBJECT> <SECTNO>218.304</SECTNO> <SUBJECT>May I credit rental towards direct use fees?</SUBJECT> <SECTNO>218.305</SECTNO> <SUBJECT>How do I pay advanced royalties I owe under BLM regulations?</SUBJECT> <SECTNO>218.306</SECTNO> <SUBJECT>May I receive a credit against production royalties for in-kind deliveries of electricity I provide under contract to a State or county government?</SUBJECT> <SECTNO>218.307</SECTNO> <SUBJECT>How do I pay royalties due for my existing leases that qualify for near-term production incentives under BLM regulations?</SUBJECT> </SUBPART> <SUBPART> <RESERVED>Subpart G—Indian Lands [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Service of Official Correspondence</HD> <SECTNO>218.500</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <SECTNO>218.520</SECTNO> <SUBJECT>What definitions apply to this subpart?</SUBJECT> <SECTNO>218.540</SECTNO> <SUBJECT>How does MMS serve official correspondence?</SUBJECT> <SECTNO>218.560</SECTNO> <SUBJECT>How do I submit Form MMS-4444?</SUBJECT> <SECTNO>218.580</SECTNO> <SUBJECT>When do I submit Form MMS-4444?</SUBJECT> </SUBPART> </CONTENTS> <AUTH> <HD SOURCE="HED">Authority:</HD> <P>25 U.S.C. 396 <E T="03">et seq.,</E> 396a <E T="03">et seq.,</E> 2101 <E T="03">et seq.</E>; 30 U.S.C. 181 <E T="03">et seq.,</E> 351 <E T="03">et seq.,</E> 1001 <E T="03">et seq.,</E> 1701 <E T="03">et seq.</E>; 31 U.S.C. 3335; 43 U.S.C. 1301 <E T="03">et seq.,</E> 1331 <E T="03">et seq.,</E> and 1801 <E T="03">et seq.</E> </P> </AUTH> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>48 FR 35641, Aug. 5, 1983, unless otherwise noted.</P> </SOURCE> <SUBPART> <PRTPAGE P="195"/> <HD SOURCE="HED">Subpart A—General Provisions</HD> <SECTION> <SECTNO>§ 218.10</SECTNO> <SUBJECT>Information collection.</SUBJECT> <P>The information collection requirements contained in this part have been approved by OMB under 44 U.S.C. 3501 <E T="03">et seq.</E> The forms, filing date, and approved OMB clearance numbers are identified in 30 CFR 210.10.</P> <CITA>[57 FR 41867, Sept. 14, 1992]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.40</SECTNO> <SUBJECT>Assessments for incorrect or late reports and failure to report.</SUBJECT> <P>(a) An assessment of an amount not to exceed $10 per day may be charged for each report not received by MMS by the designated due date.</P> <P>(b) An assessment of an amount not to exceed $10 may be charged for each incorrectly completed report.</P> <P>(c) For purposes of assessments discussed in this section, a report is defined as follows:</P> <P>(1) For coal and other solid mineral leases, a report is each line on the Solid Minerals Production and Royalty Report, Form MMS-4430.</P> <P>(2) For oil and gas and geothermal leases, a report is each line on the Report of Sales and Royalty Remittance, Form MMS-2014.</P> <P>(d) An assessment under this section shall not be shared with a State, Indian tribe, or Indian allottee.</P> <P>(e) The amount of the assessment to be imposed pursuant to paragraphs (a) and (b) of this section shall be established periodically by MMS. The assessment amount for each violation will be based on MMS's experience with costs and improper reporting. The MMS will publish a Notice of the assessment amount to be applied in the <E T="04">Federal Register.</E> </P> <CITA>[49 FR 37346, Sept. 21, 1984. Redesignated and amended at 51 FR 15767, Apr. 28, 1986; 52 FR 27546, July 22, 1987; 52 FR 37452, Oct. 7, 1987; 57 FR 52720, Nov. 5, 1992; 59 FR 38906, Aug. 1, 1994; 66 FR 45773, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.41</SECTNO> <SUBJECT>Assessments for failure to submit payment of same amount as Form MMS-2014 or bill document or to provide adequate information.</SUBJECT> <P>(a) An assessment of an amount not to exceed $250 may be charged when the amount of a payment submitted by a payor is not equivalent in amount to the total of individual line items on the associated Form MMS 2014 or bill document, unless the difference in amount has been authorized by MMS.</P> <P>(b) An assessment of an amount not to exceed $250 may be charged for each payment submitted by a payor that cannot be automatically applied by AFS to the associated Form MMS-2014 or bill document because of inadequate or erroneous information submitted by the payor. For purposes of this section, inadequate or erroneous information is defined as:</P> <P>(1) Absent or incorrect payor assigned document number, required to be identified by the payor in Block 3a on a Form MMS-2014, or the reuse of the same payor assigned document (“3a”) number in a subsequent reporting period.</P> <P>(2) Absent or incorrect bill document invoice number (to include the four character alpha prefix and the eight digit number) or the payor-assigned 3a number required to be identified by the payor on the associated payment document, or the reuse of the same payor assigned 3a number in a subsequent reporting period.</P> <P>(3) Absent or incorrect name of the administering Bureau of Indian Affairs Agency/Area office and the word “allotted” or the tribe name on payment documents remitted to MMS for an Indian tribe or allottee. If the payment is made by EFT, the payor must identify the tribe/allottee on the EFT message by a pre-established five digit code.</P> <P>(4) Absent or incorrect MMS assigned payor code on a payment document.</P> <P>(c) For purposes of this section, the term “Form MMS-2014” includes submission of reports of royalty information by magnetic media. Magnetic media submissions include submissions by magnetic tape, magnetic cartridge, or floppy diskette.</P> <P>(d) For purposes of this section, a bill document is defined as any Bill of Collection (Form DI-1040b) that has been issued by MMS for assessments, late-payment interest charges, or other amounts owed.</P> <P>(e) For purposes of this section, a payment document is defined as one of the payment methods identified in § 218.51(a)(3).</P> <P>(f) The amount of the assessment to be imposed pursuant to paragraphs (a) <PRTPAGE P="196"/>and (b) of this section shall be established periodically by MMS. The assessment amount will be based on MMS' experience with costs and improper reporting and/or payment as specified in this section. The MMS will publish a Notice in the <E T="04">Federal Register</E> of the assessment amount to be applied with the effective date.</P> <CITA>[58 FR 45438, Aug. 30, 1993]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.42</SECTNO> <SUBJECT>Cross-lease netting in calculation of late-payment interest.</SUBJECT> <P>(a) Interest due from a payor on any underpayment for any Federal mineral lease or leases (onshore or offshore) and on any Indian tribal mineral lease or leases for any production month shall not be reduced by offsetting against that underpayment any overpayment made by the payor on any other lease or leases, except as provided in paragraph (b) of this section. Interest due from a payor or any underpayment on any Indian allotted lease shall not be reduced by offsetting against any overpayment on any other Indian allotted lease under any circumstances.</P> <P>(b) Royalties attributed to production from a lease or leases which should have been attributed to production from a different lease or leases may be offset to determine whether and to what extent an underpayment exists on which interest is due if the following conditions are met:</P> <P>(1) The error results from attributing and reporting an equal volume of production, produced from a lease or leases during a particular production month, to a different lease or leases from which it was not produced for the same or another production month;</P> <P>(2) The payor is the same for the lease or leases to which production was attributed and the lease or leases to which it should have been attributed;</P> <P>(3) The payor submits production reports, pipeline allocation reports, or other similar documentary evidence pertaining to the specific production involved which verifies the correct production information;</P> <P>(4) The lessor is the same for the leases involved (in the case of Indian tribal leases, the same tribe is the lessor); and</P> <P>(5) The ultimate recipients of any royalty or other lease revenues under any applicable permanent indefinite appropriations are the same for, and receive the same percentage of revenue from, the leases.</P> <P>(c) If MMS assesses late-payment interest and the payor asserts that some or all of the interest assessed is not owed pursuant to the exception set forth in paragraph (b) of this section, the burden is on the payor to demonstrate that the exception applies in the specific circumstances of the case.</P> <P>(d) The exception set forth in paragraph (b) of this section shall not operate to relieve any payor of liability imposed by statute or regulation for erroneous reporting.</P> <CITA>[57 FR 62206, Dec. 30, 1992]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart B—Oil and Gas, General</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>49 FR 37346, Sept. 21, 1984, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 218.50</SECTNO> <SUBJECT>Timing of payment.</SUBJECT> <P>(a) Royalty payments are due at the end of the month following the month during which the oil and gas is produced and sold except when the last day of the month falls on a weekend or holiday. In such cases, payments are due on the first business day of the succeeding month. Rental payments are due as specified by the lease terms.</P> <P>(b) Payments made on a Bill for Collection (Form DI-1040b) are due as specified by the Bill. Bills for Collection will be issued and payable as final collection actions.</P> <P>(c) All payments to MMS are due as specified and are not deferred or suspended by reason of an appeal having been filed unless such deferral or suspension is approved in writing by an authorized MMS official.</P> <P>(d)(1) Notwithstanding the provisions of paragraph (a) of this section and corresponding lease terms and 30 CFR 210.52, the due date for submittal of royalty payments and Reports of Sales and Royalty Remittance (Form MMS-2014) for the production months of July, August, September, and October 2005 for Federal offshore and onshore oil and gas leases by oil and gas lessees <PRTPAGE P="197"/>or royalty payors who make the certification required under paragraph (d)(2) of this section is extended until January 3, 2006.</P> <P>(2) The extended due dates in paragraph (d)(1) of this section will apply to royalty payments and Reports of Sales and Royalty Remittance (Form MMS-2014) by any lessee or royalty payor who certifies that a hurricane that struck the Gulf of Mexico coast of the United States in August or September 2005 disrupted the lessee's or payor's operations to the extent that it prevented the lessee or royalty payor from making an accurate royalty payment or submitting an accurate Form MMS-2014.</P> <P>(3) A lessee's or royalty payor's certification under paragraph (d)(2) of this section that it is unable to generate and submit either an accurate royalty report or an accurate royalty payment will extend the due date for both royalty reporting and royalty payment.</P> <P>(4) Paragraphs (d)(1) through (d)(3) of this section do not apply to Indian leases or to Federal leases for minerals other than oil and gas.</P> <P>(5) Certifications under paragraph (d)(2) of this section should be submitted either:</P> <P>(i) By mail to: Robert Prael, Financial Manager, Minerals Management Service, Minerals Revenue Management, P.O. Box 25165, MS 350B1, Denver, CO 80225-0165, or</P> <P>(ii) By e-mail to <E T="03">Robert.Prael@mms.gov</E>.</P> <P>(e)(1) A lessee or royalty payor who submits a certification required under paragraph (d)(2) of this section may rely on the extended due dates prescribed in paragraph (d)(1) of this section unless and until MMS notifies the lessee or royalty payor or operator that MMS does not accept the certification.</P> <P>(2) If MMS notifies the lessee or royalty payor that MMS does not accept the lessee's or royalty payor's certification under paragraph (d)(2) of this section, the due date for royalty payments and Reports of Sales and Royalty Remittance will be the date specified in the notice.</P> <CITA>[49 FR 37346, Sept. 21, 1984, as amended at 70 FR 56853, Sept. 29, 2005]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.51</SECTNO> <SUBJECT>How to make payments.</SUBJECT> <P>(a) <E T="03">Definitions.</E> </P> <P> <E T="03">ACH</E>—Automated Clearing House. A type of EFT using the ACH network.</P> <P> <E T="03">Courtesy Notice</E>—An MMS-issued notice of rental or bonus due.</P> <P> <E T="03">Deferred Bonus Payment</E>—Lease bonus paid in equal annual installments over a specified number of years.</P> <P> <E T="03">EFT</E>—Electronic Funds Transfer. Any paperless transfer of funds a bank initiates through an electronic terminal. For MMS purposes, EFT is limited to FEDWIRE and ACH transfers.</P> <P> <E T="03">FEDWIRE</E>—A type of EFT using the Federal Reserve Wire network.</P> <P> <E T="03">Invoice Document Identification</E>—The MMS-assigned invoice document identification (four alpha and eight numeric characters).</P> <P> <E T="03">Payment</E>—Any monies for royalty, bonus, rental, late payment charge, assessment, penalty, or other money sent to MMS.</P> <P> <E T="03">Person</E>—Any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity). The term does not include Federal agencies.</P> <P> <E T="03">Report</E>—Form MMS-2014, <E T="03">Report of Sales and Royalty Remittance.</E> </P> <P> <E T="03">RIK</E>—Royalty in kind.</P> <P>(b) <E T="03">General Instructions.</E> You must make all payments to MMS electronically to the extent it is cost effective and practical. If you pay money to MMS or to an Indian tribe or allottee, you must follow these procedures:</P> <P>(1) If MMS instructs you to use EFT, you must use EFT for all payments to MMS and/or a tribe.</P> <P>(2) Contact MMS before using EFT. MMS will provide you with EFT payment instructions.</P> <P>(3) Separate any payments on a Federal lease from any payments on an Indian lease.</P> <P>(4) If you are not required to use EFT, use one of the following types of payment documents. MMS prefers that you use these payment documents in the order presented:</P> <P>(i) Commercial check drawn on a solvent bank;</P> <P>(ii) Certified check;</P> <P>(iii) Cashier's check;</P> <P>(iv) Money order;</P> <P>(v) Bank draft drawn on a solvent bank; or<PRTPAGE P="198"/> </P> <P>(vi) Federal Reserve check.</P> <P>(5) You must include your payor code on all payments.</P> <P>(6) You must pay in U.S. dollars.</P> <P>(c) <E T="03">How to complete a non-EFT payment.</E> (1) Make any payment on a Federal lease payable to: “Department of the Interior-Minerals Management Service” or “DOI-MMS.”</P> <P>(2) For an Indian allottee payment, send a separate payment for each Bureau of Indian Affairs (BIA) agency or area office represented by the leases on your report or invoice document. You must include the name of the applicable BIA agency or area office on your payment. Make your payment document payable to: “Department of the Interior-Minerals Management Service for BIA [Name] Agency (allotted)” or “DOI-MMS for BIA [Name] Agency (allotted).”</P> <P>(3) For an Indian tribal payment other than a lockbox payment, send a separate payment for each tribe represented by the leases on your report or invoice document. You must include the name of the Indian tribe on your payment. Make it payable to: “Department of the Interior-Minerals Management Service for BIA [Name of Tribe]” or “DOI-MMS for BIA [Name of Tribe].”</P> <P>(4) For an Indian tribal lockbox payment, follow the instructions MMS provides you on how to report and make the lockbox payment. These instructions are specific to each tribe's lockbox written agreement with the bank authorized to receive payments on the tribe's mineral leases. You will receive these instructions from MMS when you are required to use a tribal lockbox for reports and payments.</P> <P>(d) <E T="03">Where to send a non-EFT payment when you use the U.S. Postal Service.</E> (1) For a payment to an Indian tribal lockbox, send your payment to the appropriate tribal lockbox address.</P> <P>(2) For a Federal nonproducing lease rental or deferred bonus payment, send it to: </P> <EXTRACT> <FP SOURCE="FP-1">Minerals Management Service, Minerals Revenue Management, P.O. Box 5640, Denver, CO 80217-5640.</FP> </EXTRACT> <P>(3) For all other Federal and Indian lease payments other than those going to an Indian tribal lockbox, send them to: </P> <EXTRACT> <FP SOURCE="FP-1">Minerals Management Service, Minerals Revenue Management, P.O. Box 5810, Denver, CO 80217-5810.</FP> </EXTRACT> <P>(e) <E T="03">Where to send a non-EFT payment when you use a courier or overnight delivery service.</E> You should send this type of payment to: </P> <EXTRACT> <FP SOURCE="FP-1">Minerals Management Service, Minerals Revenue Management, Building 85, Denver Federal Center, Room A-614, Denver, CO 80225-0165.</FP> </EXTRACT> <P>(f) <E T="03">How to prepare and what to include on your payment document.</E> (1) For Form MMS-2014 payments, you must include both your payor code (block 2) and your payor-assigned document number (block 3a).</P> <P>(2) For invoice payments, including RIK invoice payments, you must include both your payor code and invoice document identification (four-letter prefix and eight-digit number).</P> <P>(3) For bonus payments:</P> <P>(i) For one-fifth bonus payments for offshore oil, gas, and sulphur leases, follow the instructions in the Notice of Lease Offering.</P> <P>(ii) For payment of the four-fifths bonus for an offshore lease, use EFT and follow the instructions in § 218.155(c).</P> <P>(iii) For the successful bidder's bonus in the competitive sale of a coal, geothermal, or offshore mineral (other than oil, gas or sulfur) lease, follow the instructions and terms of the Notice of Competitive Lease Sale.</P> <P>(iv) For installment payments of deferred bonuses, you must use EFT.</P> <P>(4) If you are paying a lease rental you must:</P> <P>(i) See 30 CFR 218.155(c) for instructions on how to pay first-year rentals of an offshore oil, gas, or sulfur lease;</P> <P>(ii) See the Notice of Lease Offering for instructions on how to pay first-year rentals other than those covered in paragraph (f)(4)(i) of this section.</P> <P>(iii) Include the MMS Courtesy Notice, when provided, or write your payor code and government-assigned lease number on the payment document when paying a rental that is not reported on Form MMS-2014 and not paid by EFT.</P> <P>(g) <E T="03">When is a payment to MMS due?</E> (1) All payments are due to MMS at the time law, regulation, or lease terms require unless MMS approves a change <PRTPAGE P="199"/>according to part 243 of this chapter. If you file an appeal, and the requirement to submit payment is suspended, the original payment due date for purposes such as calculating late payment interest is not changed.</P> <P>(2) If you use the U.S. Postal Service, courier, or overnight mail to send your payment, it is due at the MMS addresses in paragraphs (d) and (e) of this section before 4 p.m. Mountain Time on the due date, regardless of when you sent it.</P> <P>(3) If you use EFT to send your payment, it is due in the MMS account by the payment due date. You are responsible for your actions or your bank's actions that cause a late or incorrect payment. You will not be held responsible for mechanical or system failures of EFT payments.</P> <P>(h) <E T="03">What happens if payments are late or overdue?</E> (1) If MMS receives your payment late, MMS will impose a late-payment interest charge under 30 CFR 218.54.</P> <P>(2) If you do not pay an amount you owe, MMS may assess civil penalties under part 241 of this chapter or other applicable regulations.</P> <CITA>[62 FR 19498, Apr. 22, 1997, as amended at 66 FR 45773, Aug. 30, 2001; 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.52</SECTNO> <SUBJECT>How does a lessee designate a Designee?</SUBJECT> <P>(a) If you are a lessee under 30 U.S.C. 1701(7), and you want to designate a person to make all or part of the payments due under a lease on your behalf under 30 U.S.C. 1712(a), you must notify MMS or the applicable delegated State in writing of such designation. Your notification for each lease must include the following:</P> <P>(1) The AID number for the lease;</P> <P>(2) The type of products you make payments for e.g., oil, gas.</P> <P>(3) The type of payments you are responsible for e.g., royalty, minimum royalty, rental.</P> <P>(4) Whether you are:</P> <P>(i) A lessee of record (record title owner) in the lease, and the percentage of your record title ownership in the lease; or</P> <P>(ii) An operating rights owner (working interest owner) in the lease, and the percentage of your operating rights ownership in the lease;</P> <P>(5) The name, address, Taxpayer Identification Number (TIN), and phone number of your Designee;</P> <P>(6) The name, address, and phone number of the individual to contact for the person you named in paragraph (a)(5) of this section;</P> <P>(7) Your TIN;</P> <P>(8) The date the designation is effective;</P> <P>(9) The date the designation terminates, if applicable, and</P> <P>(10) A copy of the written designation;</P> <P>(b) The person you designate under paragraph (a) of this section is your Designee under 30 U.S.C. 1701(24) and 30 U.S.C. 1712(a).</P> <P>(c) If you want to terminate a designation you made under paragraph (a) of this section, you must provide to MMS in writing before the termination:</P> <P>(1) The date the designation is due to terminate; and</P> <P>(2) If you are not reporting and paying royalties and making other payments to MMS, a new designation under paragraph (a) of this section.</P> <P>(d) MMS may require you to provide notice when there is a change in the percentage of your record title or operating rights ownership.</P> <CITA>[62 FR 42066, Aug. 5, 1997]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.53</SECTNO> <SUBJECT>Recoupment of overpayments on Indian mineral leases.</SUBJECT> <P>(a) Whenever an overpayment is made under an Indian oil and gas lease, a payor may recoup the overpayment through a recoupment on Form MMS-2014 against the current month's royalties or other revenues owed on the same lease. However, for any month a payor may not recoup more than 50 percent of the royalties or other revenues owed in that month under an individual allotted lease or more than 100 percent of the royalties or other revenues owed in that month under a tribal lease.</P> <P>(b) With written permission authorized by tribal statute or resolution, a payor may recoup an overpayment against royalties or other revenues owed in that month under other leases for which that tribe is the lessor. A <PRTPAGE P="200"/>copy of the tribe's written permission must be furnished to MMS pursuant to instructions for reporting recoupments in the MMS revenue reporter handbook. See part 210 of this chapter. Recouping overpayments on one allotted lease from royalties paid to another allotted lease is specifically prohibited.</P> <P>(c) Overpayments subject to recoupment under this section include all payments made in excess of the required payment for royalty, rental, bonus, or other amounts owed as specified by statute, regulation, order, or terms of an Indian mineral lease.</P> <P>(d) The MMS Director or his/her designee may order any payor to not recoup any amount for such reasonable period of time as may be necessary for MMS to review the nature and amount of any claimed overpayment.</P> <CITA>[60 FR 3087, Jan. 13, 1995, as amended at 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.54</SECTNO> <SUBJECT>Late payments.</SUBJECT> <P>(a) An interest charge shall be assessed on unpaid and underpaid amounts from the date the amounts are due.</P> <P>(b) The interest charge on late payments shall be at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).</P> <P>(c) Interest will be charged only on the amount of the payment not received. Interest will be charged only for the number of days the payment is late.</P> <P>(d) A portion of the interest collected will be paid to a State where the State shares in mineral revenues from Federal leases.</P> <P>(e) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.</P> <CITA>[49 FR 37346, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990; 57 FR 62206, Dec. 30, 1992]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.55</SECTNO> <SUBJECT>Interest payments to Indians.</SUBJECT> <P>(a) All interest collected from unpaid or underpayments on Indian tribal or allotted leases will be paid to the tribe or allottee.</P> <P>(b) Any disbursement of Indian mineral revenues not made by the due date as required in § 219.103 of this chapter shall accrue interest.</P> <P>(c) Interest shall be computed at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).</P> <P>(d) The interest shall be payable only for the number of days the disbursement is late.</P> <CITA>[49 FR 37346, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.56</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart shall have the same meaning as in 30 U.S.C. 1702.</P> <CITA>[49 FR 37346, Sept. 21, 1984. Redesignated at 51 FR 15767, Apr. 28, 1986]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.57</SECTNO> <SUBJECT>Providing information and claiming rewards.</SUBJECT> <P>(a) <E T="03">General.</E> (1) If a person has any information that could lead to the recovery of royalty or other payments owed to the United States with respect to any oil and gas lease on Federal lands or the Outer Continental Shelf, such information may be provided to the Minerals Management Service (MMS) in accordance with this paragraph. The MMS is authorized, under the Federal Oil and Gas Royalty Management Act of 1982 (FOGRMA), 30 U.S.C. 1723, to pay a reward for information with respect to Federal oil and gas leases. Funds must be appropriated before payment of any reward. Criteria and procedures covering claims for and payment of rewards are provided in paragraphs (b), (c), and (d) of this section.</P> <P>(2) If a person has any information he or she believes would be valuable to MMS, that person (“informant”) should submit the information in writing, in the form of a letter, mailed or delivered in person to the Director, Minerals Management Service, Department of the Interior, 18th and C Street, NW., Washington, DC 20240, or to the Director's designated representative. Although written communications are preferred, oral information will be accepted.<PRTPAGE P="201"/> </P> <P>(3) The informant should provide all data he or she has with respect to royalty or other payments owed. The information provided should include: identification of the alleged debtor; the source of the informant's knowledge of royalties or other payments owed; the date, if known, of the indebtedness; and any other information that could be used to establish indebtedness. All information received by MMS from persons providing information will be considered “highly confidential” and will not be disclosed to any individual except on a “need to know” basis in the performance of official duties.</P> <P>(b) <E T="03">Claim for reward.</E> (1) Any informant who provides information that could lead to the recovery of royalty or other payments may file a claim for reward unless the person is an officer or employee of the United States, an officer or employee of a State or Indian tribe acting pursuant to a cooperative agreement or delegation under the FOGRMA, or any person acting pursuant to a contract authorized by the FOGRMA.</P> <P>(2) A claim for reward is not acceptable if filed on behalf of a claimant by his or her agent under power of attorney. However, an agent may provide MMS with information for an unidentified informant, to be evaluated and used by MMS as it deems appropriate. The informant's identity ultimately must be disclosed if the informant intends to file a claim for reward so that MMS can report the reward as taxable income to the Internal Revenue Service. An executor, administrator, or other legal representative of a deceased informant may file a claim on behalf of such deceased informant if, prior to his or her death, the informant was eligible to file a claim under this section. The representative must attach to the claim evidence of authority to file it.</P> <P>(3) To file a claim for reward the informant must:</P> <P>(i) Notify the Director, MMS, or the person to whom the information was reported, that he/she is claiming a reward.</P> <P>(ii) Request an “Application for Reward for Original Information” (Form MMS-4280). This form provides for information to enable MMS to determine and pay rewards, to control reward applications, and to report a claimant's reward as taxable income to the Internal Revenue Service.</P> <P>(iii) File a claim for reward by completing Form MMS-4280, sign it with his or her true name, and mail or deliver it in person to the Director or to the Director's designated representative. If the informant provided the information in person, the claim should include the name and title of the person to whom the information was reported and the date that it was reported.</P> <P>(4) If the informant used an identity other than his or true name when the information was originally reported, the person should attach proof to the claim that he or she is the person who gave the information. The MMS does not disclose the identity of its informants to unauthorized persons.</P> <P>(c) <E T="03">Basis for rejection of claims.</E> No reward will be paid to a claimant:</P> <P>(1) Where the information originally furnished was deemed unworthy of initiating an investigation, but at some later date the records of the lessee are examined without reference to the information furnished. The claim will be rejected on the basis that the information did not cause the investigation nor did it, in itself, result in any recovery.</P> <P>(2) For information that would have been discovered during the normal course of an audit or investigation.</P> <P>(3) Unless the informant's true identity is disclosed.</P> <P>(4) Until after all of the royalties, penalties, or other payments discovered to be owed as a result of information provided are collected and no longer subject to dispute.</P> <P>(5) Unless funds are appropriated for the payment of rewards.</P> <P>(d) <E T="03">Basis for allowance of claims.</E> (1) The value of the information furnished in relation to the facts developed by the investigation will be taken into account in determining whether a reward shall be paid and, if so, the amount thereof. Information must be voluntarily given and upon the informant's own initiative to warrant the allowance of a reward. Information secured by representatives of MMS from witnesses and others in the course of their <PRTPAGE P="202"/>investigative activities does not constitute a basis for reward.</P> <P>(2) In determining whether a reward will be allowed and, if so, the amount thereof, consideration will be given to any corresponding adjustment(s) which will result in potential savings to the lessee for other leases owned by the lessee or an affiliate of the lessee. An example of such an adjustment is a reduction in royalty payment on a different lease as the result of a revised allocation under a unitization or communitization agreement or from an offshore pipeline system. Rewards otherwise allowable will be reduced or rejected by reason of such offsetting adjustments.</P> <P>(3) If several claims filed by one informant are considered in one recommendation, the reward, if any, may be allowed on one claim and the others may be closed by reference.</P> <P>(4) Where an informant has provided information and filed a claim for reward with respect to royalty reports of one lessee for several leases, no reward will be granted with respect to an individual lease which has been examined until examination of all leases involved has been completed. Because the possibility exists that adjustments made to the reports for the open leases may result in offsetting adjustments, no reward will be allowed until the overall results of the information are evaluated.</P> <P>(e) <E T="03">Amount and payment of reward.</E> (1) The Director, MMS will determine whether a reward will be paid and, if so, the amount thereof. In making this decision, the information provided will be evaluated in relation to the facts developed by the resulting investigation. Claims for reward will be paid in proportion to the value of information furnished voluntarily and on the informant's own initiative with respect to recovered royalties or other payments. The amount of reward will be determined as follows:</P> <P>(i) For specific and responsible information that caused the investigation and resulted in recovery, the reward will be 10 percent of the first $75,000 recovered, 5 percent of the next $25,000, and 1 percent of any additional recovery. The total reward cannot exceed $100,000.</P> <P>(ii) For information that caused the examination and was of value in determining royalty or other payments due, although not specific, and for information that was a direct factor in recovering royalty or other payments, the reward will be 5 percent of the first $75,000 recovered, 2<FR>1/2</FR> percent of the next $25,000, and <FR>1/2</FR> percent of any additional recovery. The total reward cannot exceed $100,000.</P> <P>(iii) For information that caused the investigation but was of no value in determining royalty or other payments due, the reward will be 1 percent of the first $75,000 recovered and <FR>1/2</FR> percent of any additional recovery. The total reward cannot exceed $100,000.</P> <P>(2) Rewards will be paid only if moneys are appropriated for that purpose. Subject to appropriations, payments will be made as soon as possible after collection of the amounts owed by the lessee, and after those amounts no longer are subject to dispute by the payor. The reward payment to an informant will be net of Federal and State income tax in accordance with withholding guidelines of the Internal Revenue Service and the applicable State(s).</P> <P>(3) A decision by the Director, MMS, either denying a reward or establishing the amount of any reward is a final departmental action and may not be appealed to the Interior Board of Land Appeals in accordance with the provisions of 30 CFR part 290.</P> <APPRO>(Approved by the Office of Management and Budget under control number 1010-0076)</APPRO> <CITA>[52 FR 24451, July 1, 1987]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart C—Oil and Gas, Onshore</HD> <SECTION> <SECTNO>§ 218.100</SECTNO> <SUBJECT>Royalty and rental payments.</SUBJECT> <P>(a) <E T="03">Payment of royalties and rentals.</E> As specified under the provisions of the lease, the lessee shall submit all rental payments when due and shall pay in value or deliver in production all royalties in the amounts of value or production determined by MMS to be due.</P> <P>(b) If the lessor elects to take royalty in oil or gas, unless otherwise agreed upon, such royalty shall be delivered on the leasehold, by the lessee to the order of and without cost to the lessor, <PRTPAGE P="203"/>as instructed by the Associate Director.</P> <P>(c) <E T="03">Method of payment.</E> The payor shall tender all payments in accordance with 30 CFR 218.51.</P> <CITA>[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 52 FR 23815, June 25, 1987]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.101</SECTNO> <SUBJECT>Royalty and rental remittance (naval petroleum reserves).</SUBJECT> <P>Remittance covering payments of royalty or rental on naval petroleum reserves must be accomplished by necessary identification information and sent direct to the Director, Naval Petroleum Reserves in California.</P> <CITA>[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.102</SECTNO> <SUBJECT>Late payment or underpayment charges.</SUBJECT> <P>(a) The failure to make timely or proper payments of any monies due pursuant to leases, permits, and contracts subject to these regulations will result in the collection by the MMS of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the payor. However, late payment charges assessed with respect to any Indian lease, permit, or contract shall be collected and paid to the Indian or tribe to which the amount overdue is owed.</P> <P>(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51. Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.</P> <P>(c) Late payment charges apply to all underpayments and payments received after the date due. The charges include production and minimum royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/permittee/payor/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due amounts, including late-payment charges, will result in the initiation of other enforcement proceedings.</P> <P>(d) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.</P> <CITA>[47 FR 47773, Oct. 27, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 49 FR 37347, Sept. 21, 1984; 57 FR 41868, Sept. 14, 1992; 57 FR 62206, Dec. 30, 1992; 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.103</SECTNO> <SUBJECT>Payments to States.</SUBJECT> <P>(a) Any amount that is payable by MMS to a State but is not paid on the due date, as specified in § 219.100 of this chapter, or that is held in a suspense account pending resolution of a dispute as specified in § 219.101 of this chapter, shall accrue interest payable to the State.</P> <P>(b) Interest shall be computed at the underpayment rate established by the Internal Revenue Code, 26 U.S.C. 6621(a)(2) (Supp. 1987).</P> <P>(c) Interest shall be computed only for the number of days the disbursement is late. In the case of suspended amounts subject to interest, it shall be computed beginning with the calendar day following the day that the monies normally would have been paid to the State had they not been in suspense.</P> <CITA>[49 FR 37347, Sept. 21, 1984, as amended at 55 FR 37230, Sept. 10, 1990]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.104</SECTNO> <SUBJECT>Exemption of States from certain interest and penalties.</SUBJECT> <P>(a) States are exempt from being assessed for any interest or penalties found to be due against the Department of the Interior for failure to comply with the Emergency Petroleum Allocation Act of 1973, as amended, or any regulation issued by the Secretary of Energy thereunder concerning the certification or processing of crude oil taken in-kind as royalty by the Secretary.</P> <P>(b) Any State shall be assessed for its share of any overcharge resulting from a determination that DOI failed to comply with the Emergency Petroleum <PRTPAGE P="204"/>Allocation Act of 1973, as amended. Each State's share shall be assessed against monies owed to the State. Such assessment shall be first against monies owed to such State as a result of royalty audits prior to January 12, 1983, the enactment date of the Federal Oil and Gas Royalty Management Act of 1982, then against other monies owed. The State shall be liable for any balance.</P> <P>(c) A State's liability for repayment of an overcharge under this section shall exist for any amounts resulting from a judgment in a civil suit or as the result of settlement of a claim through a negotiated agreement. State liability would be offset against future mineral revenue distributions to the State.</P> <CITA>[49 FR 37347, Sept. 21, 1984]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.105</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.</P> <CITA>[49 FR 37347, Sept. 21, 1984]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart D—Oil, Gas and Sulfur, Offshore</HD> <SECTION> <SECTNO>§ 218.150</SECTNO> <SUBJECT>Royalties, net profit shares, and rental payments.</SUBJECT> <P>(a) As specified under the provisions of the lease, the lessee shall submit all rental payments when due and shall pay in value or deliver in production all royalties and net profit shares in the amounts of value or production determined by MMS to be due.</P> <P>(b) The failure to make timely or proper payments of any monies due pursuant to leases, permits, and contracts subject to these regulations will result in the collection of the amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the payor.</P> <P>(c) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51. Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.</P> <P>(d) Late payment charges apply to all underpayments and payments received after the date due. These charges include production and minimum royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/payor/permittee/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due amounts, including late payment charges, will result in the initiation of other enforcement proceedings.</P> <P>(e) An overpayment on a lease or leases, excluding rental payments, may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.</P> <CITA>[47 FR 22528, May 25, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and amended at 49 FR 37347, Sept. 21, 1984; 52 FR 23815, June 25, 1987; 57 FR 41868, Sept. 14, 1992; 57 FR 62206, Dec. 30, 1992; 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.151</SECTNO> <SUBJECT>Rental fees.</SUBJECT> <P>The annual rental paid in any year is in addition to, and is not credited against, any royalties due from production. The lessee must pay an annual rental as shown in paragraphs (a), (b), and (c) of this section. Discovery means one or more wells on the lease that meet the requirements in 250, subpart A of this title.</P> <P>(a) This paragraph applies to any lease not covered by paragraph (b) or paragraph (c) of this section.</P> <GPOTABLE CDEF="s50,r50,r100" COLS="3" OPTS="L2"> <BOXHD> <CHED H="1">For—</CHED> <CHED H="1">Issued as a result of a sale held—</CHED> <CHED H="1">The lessee must pay rental—</CHED> </BOXHD> <ROW> <ENT I="01">(1) An oil and gas lease</ENT> <ENT>Before March 26, 2001</ENT> <ENT>On or before the first day of each lease year before the discovery of oil or gas on the lease.</ENT> </ROW> <ROW> <PRTPAGE P="205"/> <ENT I="01">(2) An oil and gas lease</ENT> <ENT>After March 26, 2001</ENT> <ENT>On or before the first day of each lease year before the discovery of oil or gas on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.</ENT> </ROW> <ROW> <ENT I="01">(3) A mineral lease for other than oil or gas</ENT> <ENT>Before March 26, 2001</ENT> <ENT>On or before the first day of each lease year before the discovery of paying quantities.</ENT> </ROW> <ROW> <ENT I="01">(4) A mineral lease for other than oil or gas</ENT> <ENT>After March 26, 2001</ENT> <ENT>On or before the first day of each lease year before the date the first royalty payment is due on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.</ENT> </ROW> </GPOTABLE> <P>(b) This paragraph applies to any lease created by segregating a portion of a producing lease when there is no actual or allocated production on the segregated portion. The lessee must pay an annual rental for the segregated portion at the rate specified in the lease. The lessee must pay the rental as shown in the following table.</P> <GPOTABLE CDEF="s75,r150" COLS="2" OPTS="L2"> <BOXHD> <CHED H="1">If the lease results from a segregation—</CHED> <CHED H="1">The lessee must pay rental—</CHED> </BOXHD> <ROW> <ENT I="01">(1) Before March 26, 2001</ENT> <ENT>On or before the first day of each lease year before the discovery of oil or gas on the segregated portion.</ENT> </ROW> <ROW> <ENT I="01">(2) After March 26, 2001</ENT> <ENT>On or before the first day of each lease year before the discovery of oil or gas on the lease, then on or before the last day of each lease year in any full year in which royalties on production are not due.</ENT> </ROW> </GPOTABLE> <P>(c) For leases issued subject to the net profit sharing provisions, annual rental payments shall be due and payable in advance, on the first day of each lease year which commences prior to the date the first profit share payment becomes due. The owner of any lease created by the segregation of a portion of a lease subject to net profit sharing provisions, shall pay an annual rental for such segregated portion at the rate per acre or hectare specified in the lease. This rental shall be payable each year following the year in which the segregation becomes effective and shall continue to be due and payable, in advance, on the first day of each year which commences prior to the date the first profit share payment becomes due.</P> <CITA>[44 FR 38276, June 29, 1979, as amended at 45 FR 69175, Oct. 17, 1980; 47 FR 25972, June 16, 1982. Redesignated at 47 FR 47006, Oct. 22, 1982, and at 48 FR 35641, Aug. 5, 1983; 66 FR 11518, Feb. 23, 2001; 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.152</SECTNO> <SUBJECT>Fishermen's Contingency Fund.</SUBJECT> <P>Upon the establishment of the Fishermen's Contingency Fund, any holder of a lease issued or maintained under the Outer Continental Shelf Lands Act and any holder of an exploration permit or of an easement or right-of-way for the construction of a pipeline, shall pay an amount specified by the Director, MMS, who shall assess and collect the specified amount from each holder and deposit it into the Fund. With respect to prelease exploratory drilling permits, the amount will be collected at the time of issuance of the permit.</P> <CITA>[52 FR 5458, Feb. 23, 1987]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.153</SECTNO> <RESERVED>[Reserved]</RESERVED> </SECTION> <SECTION> <SECTNO>§ 218.154</SECTNO> <SUBJECT>Effect of suspensions on royalty and rental.</SUBJECT> <P>(a) MMS will not relieve the lessee of the obligation to pay rental or minimum royalty for or during the suspension if the Regional Supervisor:</P> <P>(1) Grants a suspension of operations or production, or both, at the request of the lessee; or</P> <P>(2) Directs a suspension of operations or production, or both, under 30 CFR 250.173(a).</P> <P>(b) MMS will not require a lessee to pay rental or minimum royalty for or during the suspension if the Regional Supervisor directs a suspension of operations or production, or both, except as provided in (a)(2) of this section.</P> <P>(c) If the lease anniversary date falls within a period of suspension for which <PRTPAGE P="206"/>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.</P> <CITA>[44 FR 38276, June 29, 1979; 44 FR 55380, Sept. 26, 1979. Redesignated and amended at 47 FR 47006, 47007, Oct. 22, 1982. Further redesignated at 48 FR 35641, Aug. 5, 1983 and amended at 51 FR 19063, May 27, 1986; 54 FR 50616, Dec. 8, 1989; 64 FR 72775, Dec. 28, 1999]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.155</SECTNO> <SUBJECT>Method of payment.</SUBJECT> <P>(a) <E T="03">Payment of royalties and rentals.</E> With the exception of first-year rental, the payor shall tender all payments in accordance with § 218.51. First-year rental shall be paid in accordance with paragraph (c) of this section.</P> <P>(b) <E T="03">Payment of the one-fifth bonus bid amount.</E> (1) Each lease bid must include a payment for the one-fifth bonus bid deposit amount unless the bidder is otherwise directed by the Secretary. Further instructions on how to make payment with the bid will be included in the notice of each lease offering. EFT may be used as a method of payment for the one-fifth bonus bid amount.</P> <P>(2) Beginning with lease offerings held after February 1, 1984, the one-fifth bonus amount received from a high bidder shall be deposited into an escrow account created pursuant to an agreement between the Departments of the Interior and Treasury, pending acceptance or rejection of the bid. The one-fifth bonus funds will be invested in public debt securities. Investment of this amount by the U.S. Government does not indicate acceptance of the bid. The one-fifth bonus checks submitted with bids other than the highest valid bid shall be returned to respective bidders after bids are opened, recorded, and ranked. Return of such checks will not affect the status, validity, or ranking of bids. The one-fifth bonus bid amount received from any high bidder and held by the Government pending acceptance or rejection, will be returned with actual interest earned, if the bid is subsequently rejected. The interest accrued during the period held in the account pending acceptance or rejection of the bid will accrue to the Government when the bid is accepted.</P> <P>(c) <E T="03">Payment of the four-fifths bonus bid amount and the first year's rental.</E> Payment shall be made to MMS by EFT unless otherwise directed by the Secretary. The payment by EFT via the FRCS must be received by the Federal Reserve Bank of New York no later than noon, eastern standard time, on the 11th business day after receipt of the lease forms by the successful bidder. A “business day” is considered to be a day on which the OCS regional office issuing the lease is open for business. The lease will not be executed by the appropriate MMS official until payment is received. Failure to remit by EFT or as directed by the Secretary within the time specified above will result in forfeiture of the one-fifth bonus bid amount and the lease will not be executed by the appropriate MMS official. Payors will not be held responsible for late payment due to actions beyond their control, such as mechanical or systems failure of FRCS or FDS. Payors will be held responsible for incorrect actions of their bank which result in late payments. A 2-day grace period will be allowed to make up a deficient payment, but a late payment charge will be assessed for this late payment and a penalty will also be assessed if appropriate. Late payment charges will be assessed in accordance with Subpart B of this part.</P> <P>(d) <E T="03">General.</E> (1) Payors using the appropriate means of payment (EFT, check, etc.) may pay for multiple lease obligations with a single remittance but must ensure that the payment complies with subpart B of this part and the remittance advice adequately identifies the single payment. The format to be used for such identification will be provided by the MMS Accounting Center.</P> <P>(2) Where to pay.</P> <P>(3) The MMS mailing addresses for payments to MMS are specified in § 218.51.<PRTPAGE P="207"/> </P> <P>(4) Payments received at the MMS addresses after 4 p.m. mountain time are considered received the following business day.</P> <P>(e) <E T="03">Miscellaneous payments.</E> Payments shall be made to the manager of the appropriate Outer Continental Shelf field office by cash, check or bank draft payable to “Department of the Interior—MMS” for miscellaneous payments such as:</P> <P>(1) Pipeline rights-of-way application filing fees and rentals, pipeline accessory site rentals and application fees, and other related costs.</P> <P>(2) Filing and approval fees for transfers of interest in leases.</P> <CITA>[49 FR 8605, Mar. 8, 1984, as amended at 52 FR 23815, June 25, 1987; 53 FR 43201, Oct. 26, 1988; 57 FR 41868, Sept. 14, 1992; 62 FR 19499, Apr. 22, 1997; 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.156</SECTNO> <SUBJECT>Definitions.</SUBJECT> <P>Terms used in this subpart have the same meaning as in 30 U.S.C. 1702.</P> <CITA>[52 FR 23815, June 25, 1987]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart E—Solid Minerals—General</HD> <SECTION> <SECTNO>§ 218.200</SECTNO> <SUBJECT>Payment of royalties, rentals, and deferred bonuses.</SUBJECT> <P>As specified under the provisions of the lease, the lessee shall submit all rental and deferred bonus payments when due and shall pay in value all royalties in the amount determined by MMS to be due.</P> <CITA>[52 FR 23815, June 25, 1987]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.201</SECTNO> <SUBJECT>Method of payment.</SUBJECT> <P>You must tender all payments in accordance with § 218.51, except as follows:</P> <P>(a) For purposes of this section, <E T="03">report</E> means the Solid Minerals Production and Royalty Report, Form MMS-4430, rather than the Form MMS-2014.</P> <P>(b) For Form MMS-4430 payments, include both your customer identification and your customer document identification numbers on your payment document, rather than the information required under § 218.51(f)(1).</P> <P>(c) For a rental payment that is not reported on Form MMS-4430, include the MMS Courtesy Notice when provided or write your customer identification number and Government-assigned lease number on the payment document, rather than the information required under § 218.51(f)(4)(iii).</P> <CITA>[66 FR 45773, Aug. 30, 2001]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.202</SECTNO> <SUBJECT>Late payment or underpayment charges.</SUBJECT> <P>(a) The failure to make timely or proper payment of any monies due pursuant to leases and contracts subject to these rules will result in the collection by MMS of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with instructions provided by MMS to the operator/lessee. However, late payment charges assessed with respect to any Indian lease, permit, or contract shall be collected and paid to the Indian or tribe to which the amount overdue is owed.</P> <P>(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51. Payments received at the specified MMS addresses after 4 p.m. mountain time are considered received the following business day.</P> <P>(c) Late payment charges are calculated on the basis of a percentage assessment rate. In the absence of a specific lease, permit, license or contract provision prescribing a different rate, this percentage assessment rate is prescribed by the Department of the Treasury as the “Treasury Current Value of Funds Rate.”</P> <P>(d) This rate is available in the Treasury Fiscal Requirements Manual Bulletins that are published prior to the first day of each calendar quarter for application to overdue payments or underpayments in the new calendar quarter. The rate is also published in the Notices section of the <E T="04">Federal Register</E> and indexed under “Fiscal Service/Notices/Funds Rate; Treasury Current Value.”</P> <P>(e) Late payment charges apply to all underpayments and payments received <PRTPAGE P="208"/>after the date due. These charges include production, minimum, or advance royalties; assessments for liquidated damages; or any other payments, fees, or assessments that an operator/lessee is required to pay by a specified date. The failure to pay past due payments, including late payment charges, will result in the initiation of other enforcement proceedings.</P> <P>(f) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.</P> <CITA>[47 FR 33195, July 30, 1982; 47 FR 53366, Nov. 26, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and further redesignated at 52 FR 23815, June 25, 1987, as amended at 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 30, 1992; 59 FR 14559, Mar. 29, 1994; 65 FR 55189, Sept. 13, 2000; 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.203</SECTNO> <SUBJECT>Recoupment of overpayments on Indian mineral leases.</SUBJECT> <P>(a) Whenever an overpayment is made under an Indian solid mineral lease, a payor may recoup the overpayment through a recoupment on Form MMS-4430 against the current month's royalties or other revenues owed on the same lease. However, for any month a payor may not recoup more than 50 percent of the royalties or other revenues owed in that month under an individual allotted lease or more than 100 percent of the royalties or other revenues owed in that month under a tribal lease.</P> <P>(b) With written permission authorized by tribal statute or resolution, a payor may recoup an overpayment against royalties or other revenues owed in that month under other leases for which that tribe is the lessor. A copy of the tribe's written permission must be furnished to MMS for reporting recoupments. Call 1-888-201-6416 for instructions. Recouping overpayments on one allotted lease from royalties paid to another allotted lease is specifically prohibited.</P> <P>(c) Overpayments subject to recoupment under this section include all payments made in excess of the required payment for royalty, rental, bonus, or other amounts owed as specified by statute, regulation, order, or terms of an Indian mineral lease.</P> <P>(d) The MMS Director or his/her designee may order any payor to not recoup any amount for such reasonable period of time as may be necessary for MMS to review the nature and amount of any claimed overpayment.</P> <CITA>[60 FR 3087, Jan. 13, 1995, as amended at 66 FR 45773, Aug. 30, 2001; 66 FR 50827, Oct. 5, 2001]</CITA> </SECTION> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart F—Geothermal Resources</HD> <SECTION> <SECTNO>§ 218.300</SECTNO> <SUBJECT>Payment of royalties, rentals, and deferred bonuses.</SUBJECT> <P>As specified under the provisions of the lease, the lessee shall submit all rental and deferred bonus payments when due and shall pay in value all royalties in the amount determined by MMS to be due.</P> <CITA>[52 FR 23815, June 25, 1987]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.301</SECTNO> <SUBJECT>Method of payment.</SUBJECT> <P>The payor shall tender all payments in accordance with 30 CFR 218.51.</P> <CITA>[52 FR 23815, June 25, 1987]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.302</SECTNO> <SUBJECT>Late payment or underpayment charges.</SUBJECT> <P>(a) The failure to make timely or proper payment of any monies due pursuant to leases and contracts subject to these regulations will result in the collection by the Minerals Management Service (MMS) of the full amount past due plus a late payment charge. Exceptions to this late payment charge may be granted when estimated payments on minerals production have already been made timely and otherwise in accordance with the instructions provided by the MMS to the payor.</P> <P>(b) Late payment charges will be assessed on any late payment or underpayment from the date that the payment was due until the date that the payment was received at the MMS addresses specified in § 218.51. Payments received at the specified MMS addresses after 4 p.m. Mountain Time are considered received the following business day.</P> <P>(c) Late payment charges are calculated on the basis of a percentage assessment rate. In the absence of a specific lease, permit, license or contract <PRTPAGE P="209"/>provision prescribing a different rate, this percentage assessment rate is prescribed by the Department of the Treasury as the “Treasury Current Value of Funds Rate.”</P> <P>(d) This rate is available in the Treasury Fiscal Requirements Manual Bulletins that are published prior to the first day of each calendar quarter for application to overdue payments or underpayments in the new calendar quarter. The rate is also published in the Notices section of the <E T="04">Federal Register</E> and indexed under “Fiscal Service/Notices/Funds Rate; Treasury Current Value.”</P> <P>(e) Late payment charges apply to all underpayments and payments received after the date due. These charges include production, minimum, and compensatory royalties; assessments for liquidated damages; administrative fees and payments by purchasers of royalty taken-in-kind; or any other payments, fees, or assessments that a lessee/operator/payor/royalty taken-in-kind purchaser is required to pay by a specified date. The failure to pay past due payments, including late payment charges, will result in the initiation of other enforcement proceedings.</P> <P>(f) An overpayment on a lease or leases may be offset against an underpayment on a different lease or leases to determine a net underpayment on which interest is due pursuant to conditions specified in § 218.42.</P> <CITA>[47 FR 22528, May 25, 1982. Redesignated at 48 FR 35641, Aug. 5, 1983, and further redesignated at 51 FR 15767, Apr. 28, 1986 and 52 FR 23815, June 25, 1987, as amended at 57 FR 41868, Sept. 14, 1992; 57 FR 62207, Dec. 30, 1992; 59 FR 14559, Mar. 29, 1994; 65 FR 55189, Sept. 13, 2000; 67 FR 19112, Apr. 18, 2002]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.303</SECTNO> <SUBJECT>May I credit rental towards royalty?</SUBJECT> <P>(a)(1) For Class II leases as defined in 30 CFR 206.351, and for Class III leases as defined in that section that elect under 43 CFR 3200.7(a)(2) to be subject to all of the BLM regulations promulgated for leases issued after August 8, 2005 you may credit the annual rental that you paid before the first day of the year for which the annual rental is owed against the royalty due for the lease year for which the rental was paid. You may not apply any annual rental paid in excess of the royalty due for a particular lease year as a credit against any royalty due in any subsequent lease year.</P> <P>(2) For purposes of this section, the term “royalty” includes any advanced royalty payable under 30 U.S.C. 1004(f) for a cessation of production.</P> <P>(b) If portions of your lease are located both within and outside of a participating area, you may credit against royalty under paragraph (a) only that percentage of the rental you paid that corresponds to the percentage of the lease within the participating area on a per-acre basis.</P> <CITA>[72 FR 24468, May 2, 2007]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.304</SECTNO> <SUBJECT>May I credit rental towards direct use fees?</SUBJECT> <P>You may not credit annual rental toward direct use fees you are required to pay that year under § 206.356(b). You must pay the direct use fees in addition to the annual rental due.</P> <CITA>[72 FR 24468, May 2, 2007]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.305</SECTNO> <SUBJECT>How do I pay advanced royalties I owe under BLM regulations?</SUBJECT> <P>If you pay advanced royalties under 43 CFR 3212.15(a)(1) to retain your lease:</P> <P>(a) You must pay an advanced royalty monthly equal to the average monthly royalty you paid under 30 CFR part 206, subpart H (including the amount against which you applied the annual rental as a credit) for the last 3 years the lease was producing. If your lease has been producing for less than 3 years, then use the average monthly royalty payment for the entire period your lease has been producing continuously;</P> <P>(b) The MMS must receive your advanced royalty payment before the end of each full calendar month in which no production occurs;</P> <P>(c) You may credit any advanced royalty you pay against production royalties you owe after your lease resumes production. You may not reduce the amount of any production royalty paid for any year below zero.</P> <CITA>[72 FR 24468, May 2, 2007]</CITA> </SECTION> <SECTION> <PRTPAGE P="210"/> <SECTNO>§ 218.306</SECTNO> <SUBJECT>May I receive a credit against production royalties for in-kind deliveries of electricity I provide under contract to a State or county government?</SUBJECT> <P>(a) You may receive a credit against royalties for in-kind deliveries of electricity you provide under contract to a State or county government if:</P> <P>(1) The State or county to which you provide electricity would receive a portion of the royalties you paid in money for the lease under 30 U.S.C. 191 or 30 U.S.C. 1019, except as otherwise provided under the Mineral Leasing Act for Acquired Lands, 30 U.S.C. 355, because your lease is located in that State or county. If your lease is located in more than one State or county, the revenues are paid to the respective States or counties based on their proportionate shares of the total acres in the lease;</P> <P>(2) The MMS approves in advance your contract with the State or county to which you are providing in-kind electricity; and</P> <P>(3) Your contract provides that you will use the wholesale value of the electricity for the area where your lease is located to establish the specific methodology to determine the amount of the credit; and</P> <P>(b) The maximum credit you may take under this section is equal to the portion of the royalty revenue that MMS would have paid to the State or county that is a party to the contract had you paid royalty in money on all of the electricity you delivered to the State or county based on the wholesale value of the electricity. You must pay in money any royalty amount that is not offset by the credit allowed under this section, calculated based on the wholesale value of the electricity.</P> <P>(c) The electricity the State or county government receives from you satisfies the Secretary's payment obligation to the State or county under 30 U.S.C. 191 or 30 U.S.C. 1019.</P> <CITA>[72 FR 24468, May 2, 2007]</CITA> </SECTION> <SECTION> <SECTNO>§ 218.307</SECTNO> <SUBJECT>How do I pay royalties due for my existing leases that qualify for near-term production incentives under BLM regulations?</SUBJECT> <P>If you qualify for a production incentive under BLM regulations at 43 CFR subpart 3212, your royalty due on the production BLM determines to be qualified for a production incentive under 43 CFR 3212.23 and 3212.24 is 50 percent of the amount of the total royalty that would otherwise be due under 30 CFR part 206, subpart H.</P> <CITA>[72 FR 24468, May 2, 2007]</CITA> </SECTION> </SUBPART> <SUBPART> <RESERVED>Subpart G—Indian Lands [Reserved]</RESERVED> </SUBPART> <SUBPART> <HD SOURCE="HED">Subpart H—Service of Official Correspondence</HD> <SOURCE> <HD SOURCE="HED">Source:</HD> <P>71 FR 51751, Aug. 31, 2006, unless otherwise noted.</P> </SOURCE> <SECTION> <SECTNO>§ 218.500</SECTNO> <SUBJECT>What is the purpose of this subpart?</SUBJECT> <P>This subpart contains instructions for designating a specific addressee of record for service of official correspondence using Form MMS-4444, Addressee of Record Designation for Service of Official Correspondence.</P> </SECTION> <SECTION> <SECTNO>§ 218.520</SECTNO> <SUBJECT>What definitions apply to this subpart?</SUBJECT> <P> <E T="03">Address of record</E> is the address to which official correspondence is served.</P> <P> <E T="03">Addressee of record for service of official correspondence</E> is the person or position to whom official correspondence is served, as specified on Form MMS-4444, or in the absence of such a form, as established in § 218.540(b)(2). The addressee of record in a part 290, subpart B, appeal will be the person or representative making the appeal.</P> <P> <E T="03">Official correspondence</E> is all correspondence from MMS or our delegates, served on companies related to matters such as: forms reporting, audit and compliance, enforcement notices, rental courtesy notices, and invoices.</P> </SECTION> <SECTION> <SECTNO>§ 218.540</SECTNO> <SUBJECT>How does MMS serve official correspondence?</SUBJECT> <P>MMS will serve all Notices of Noncompliance or Civil Penalty following the procedures in part 241. We will serve all other documents following the procedures in this section.</P> <P>(a) <E T="03">Method of service.</E> MMS will serve all official correspondence to the addressee of record by one of the following methods:<PRTPAGE P="211"/> </P> <P>(1) U.S. Postal Service mail;</P> <P>(2) Personal delivery made pursuant to the law of the State in which the service is effected; or</P> <P>(3) Private mailing service (e.g., United Parcel Service, or Federal Express), with signature and date upon delivery, acknowledging the addressee of record's receipt of the official correspondence document.</P> <P>(b) <E T="03">Selection of addressee of record information.</E> (1) We will address official correspondence to the party shown on the most recently received Form MMS-4444 for the type of correspondence at issue. The company or reporting entity is responsible for notifying MMS of any name or address changes on Form MMS-4444. The addressee of record in a part 290, subpart B, appeal will be the person or representative making the appeal.</P> <P>(2) If we do not receive addressee of record information from you on Form MMS-4444, we may use the individual name and address, position title, or department name and address in our database, based on previous formal or informal communications or correspondence for the type of official correspondence at issue. Alternately, we may obtain contact information from public records and send correspondence to:</P> <P>(i) The registered agent;</P> <P>(ii) Any corporate officer; or</P> <P>(iii) The addressee of record shown in the files of any State Secretary; Corporate Commission; Federal or state agency that keeps official records of business entities or corporations; or other appropriate public records for individuals, business entities, or corporations.</P> <P>(c) <E T="03">Dates of service.</E> Except as provided in paragraph (d) of this section, MMS considers official correspondence as served on the date that it is received at the address of record. A receipt, signed and dated by any person at that address, is evidence of service and of the date of service. If official correspondence is served in more than one manner and the dates differ, the date of the earliest service is used<E T="52">[smc1]</E>.</P> <P>(d) <E T="03">Constructive service.</E> If we cannot make delivery to the addressee of record after making a reasonable effort, we deem official correspondence as constructively served 7 days after the date that we mail the document. This provision covers situations such as those where no delivery occurs because:</P> <P>(1) The addressee of record has moved without filing a forwarding address;</P> <P>(2) The forwarding order has expired;</P> <P>(3) Delivery was expressly refused; or</P> <P>(4) The document was unclaimed and the attempt to deliver is substantiated by either:</P> <P>(i) The U.S. Postal Service;</P> <P>(ii) A private mailing service, as described in this section; or</P> <P>(iii) The person who attempted to make delivery using some other method of service.</P> </SECTION> <SECTION> <SECTNO>§ 218.560</SECTNO> <SUBJECT>How do I submit Form MMS-4444?</SUBJECT> <P>A copy of Form MMS-4444 and instructions may be obtained from MMS. It will also be posted on the MMS Web site. Submit the completed, signed form to the address designated on the Form MMS-4444 instructions.</P> </SECTION> <SECTION> <SECTNO>§ 218.580</SECTNO> <SUBJECT>When do I submit Form MMS-4444?</SUBJECT> <P>Initially, you must submit MMS Form-4444 by November 29, 2006, and subsequently, within 2 weeks of any change of y