# Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/fr%3A2014-30033 ## Record - **Collection:** Federal Register - **Document type:** Proposed Rule - **Published:** January 6, 2015 - **Citation:** 80 FR 608 ## Text DEPARTMENT OF THE INTERIOR Office of Natural Resources Revenue 30 CFR Parts 1202 and 1206 [Docket No. ONRR-2012-0004] RIN 1012-AA13 Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform AGENCY: Office of Natural Resources Revenue, Interior. ACTION: Proposed rule. SUMMARY: The Office of Natural Resources Revenue (ONRR) proposes to change the regulations governing valuation for royalty purposes of oil and gas produced from Federal onshore and offshore leases and coal produced from Federal and Indian leases. The proposed rule also consolidates definitions for oil, gas, and coal product valuation into one subpart applicable to the Federal oil and gas and Federal and Indian coal subparts. DATES: You must submit comments on or before March 9, 2015. ADDRESSES: You may submit comments to ONRR on this proposed rulemaking by any method below. Please refer to the Regulation Identifier Number (RIN) 1012-AA13 in your comments. (See also Public Availability of Comments under Procedural Matters.) • Electronically go to www.regulations.gov. In the entry titled “Enter Keyword or ID,” enter “ONRR-2012-0004,” then click “Search.” Follow the instructions to submit public comments. ONRR will post all comments. • Mail comments to Armand Southall, Regulatory Specialist, P.O. Box 25165, MS 61030A, Denver, Colorado 80225. • Hand-carry comments, or use an overnight courier service, to the Office of Natural Resources Revenue, Building 85, Room A-614, Denver Federal Center, West 6th Ave. and Kipling St., Denver, Colorado 80225. FOR FURTHER INFORMATION CONTACT: For comments or questions on procedural issues, contact Armand Southall, ONRR, telephone (303) 231-3221, or email at armand.southall@onrr.gov. The authors of the proposed rule are Sarah Inderbitzin, Richard Adamski, Michael DeBerard, Peter Christnacht, Kimbra Davis, and Lance Wenger. SUPPLEMENTARY INFORMATION: I. Background In 2007, the Royalty Policy Committee (RPC) Subcommittee on Royalty Management issued a report titled “Mineral Revenue Collection From Federal and Indian Lands and the Outer Continental Shelf.” The Subcommittee's report recommended clarification of the regulations governing onshore gas and transportation deductions to provide more certainty for ONRR, BLM, and industry, which should result in better compliance. More specifically, the Subcommittee recommended revisions to the gas valuation regulations and guidelines to address the cost-bundling issue and to facilitate the calculation of gas transportation and gas processing deductions. The Subcommittee also recommended the use of market indices for gas valuation in the context of non-arm's-length transactions in lieu of benchmarks, which have been used since 1988. The Subcommittee's report also recommended “revis(ing) and implement(ing) the regulations and guidance for calculating prices used in checking royalty compliance for solid minerals, with particular attention to non-arm's-length transactions.” The current Federal oil valuation regulations have been in effect since 2000, with a subsequent amendment relating primarily to the use of index pricing in some circumstances. The current Federal gas valuation regulations have been in effect since March 1, 1988, with various subsequent amendments relating primarily to the transportation allowance provisions. The current Federal and Indian coal valuation regulations have been in effect since March 1, 1989, with minor subsequent amendments relating primarily to the Federal black lung excise taxes, abandoned mine lands fees, State and local severance taxes, and washing and transportation allowance provisions. In the years since we wrote these regulations, the Secretary of the Interior's (Secretary) responsibility to determine the royalty value of minerals produced has not changed, but the industry and marketplace have changed dramatically. ONRR proposes these amendments to our valuation regulations to permit the Secretary to discharge the Department of the Interior's (Department) royalty valuation responsibility in an environment of continuing and accelerating change in the industry and the marketplace. The Secretary's responsibilities regarding oil and gas production from Federal leases and coal production from Federal and Indian leases require development of flexible valuation methodologies that lessees can accurately comply with in a timely manner. To increase the effectiveness and efficiency of our rules, ONRR is proposing proactive and innovative changes. We intend for this proposed rulemaking to provide regulations that (1) offer greater simplicity, certainty, clarity, and consistency in product valuation for mineral lessees and mineral revenue recipients; (2) are more understandable; (3) decrease industry's cost of compliance and ONRR's cost to ensure industry compliance; and (4) provide early certainty to industry and ONRR that companies have paid every dollar due. Therefore, ONRR proposes to amend the current regulations at 30 CFR part 1202, subpart F, and part 1206, subparts C, D, F, and J, governing the valuation, for royalty purposes, of oil, gas, and coal produced from Federal leases and coal produced from Indian leases. On May 27, 2011, ONRR published Advance Notices of Proposed Rulemaking (ANPRs) regarding the valuation, for royalty purposes, of oil, gas, and coal produced from Federal leases and coal produced from Indian leases (76 FR 30878, 30881). ONRR received responses to the Federal oil and gas valuation ANPR from 19 State, industry, industry trade association, and the general public commenters. ONRR then conducted 3 public workshops on Federal oil and gas valuation in September and October 2011 in Houston, Texas, Washington, DC, and Denver, Colorado. At the workshops, ONRR asked attendees to discuss, among other things, the use of index prices to value oil and gas, alternatives to the current requirement to track actual costs to determine transportation allowances, and alternate methods for valuing wellhead gas volumes to eliminate the requirement to trace the value of liquids removed from processed gas. ONRR received responses to the Federal and Indian coal valuation ANPR from 11 industry representative, Tribe, State, community group (representing several member groups), coal publication, and trade organization commenters. ONRR then conducted 3 public workshops on Federal and Indian coal valuation in October 2011 in Denver, Colorado; St. Louis, Missouri; and Albuquerque, New Mexico. At those workshops, ONRR asked attendees to discuss, among other things, (1) possible alternatives to the current methods that we use to value arm's-length and non-arm's-length coal sales, (2) coal comparability factors, (3) possible alternatives to the current methods we use to value coal cooperative sales of coal, (4) use of index prices to value coal, and (5) possible alternatives to the current requirements to track actual costs to determine transportation and washing allowances. ONRR considered the input from the ANPRs and the workshops and proposes this consolidated rulemaking to improve the current regulations. The proposed rule would not alter the underlying principles of the current regulations. By proposing these amendments, the Department reaffirms that the value, for royalty purposes, of crude oil and natural gas produced from Federal leases and coal produced from Federal and Indian leases is determined at or near the lease and that gross proceeds from arm's-length contracts are the best indication of market value. Like the current regulations, these proposed regulations would not restrict ONRR to a comparison of arm's-length sales of other production occurring in the field or area to value production not sold under an arm's-length contract. Thus, like the current regulations, in this proposed rule, ONRR may begin with a “downstream” price or value and determine value at the lease by allowing deductions for the cost of transporting production to downstream sales points or markets, or by allowing appropriate adjustments for location or quality. Federal and Indian lessees are not obligated to sell their production downstream of the lease. A lessee is at liberty to sell production at or near the lease, even if selling downstream might yield a higher royalty value than selling it at the lease. If a lessee chooses to sell downstream, the choice to sell downstream does not make otherwise non-deductible costs deductible (for example marketable condition and marketing costs). See Independent Petroleum Ass'n of America. v. DeWitt, 279 F.3d 1036 (D.C. Cir. 2002), cert. denied sub nom., Independent Petroleum Ass'n of America. v. Watson, 537 U.S. 1105 (2003) (“ Independent Petroleum Ass'n v. DeWitt” ); Devon Energy Corp v. Norton, No. 04-CV-0821 (GK), 2007 WL 2422005 (D.D.C. Aug. 23, 2007), aff'd sub nom., Devon Energy Corp. v. Kempthorne, 551 F.3d 1030 (D.C. Cir. 2008), cert. denied, 130 S. Ct. 86 (2009) (“ Devon” ) and cases cited therein. As noted above, the changes proposed in this rule reflect an effort by ONRR to update its royalty valuation regulations to, among other things, simplify processes and provide early clarity regarding royalties owed. However, even with the changes outlined in this rule, royalty valuations will continue to be complex, and the markets for oil, gas, and coal will continue to evolve. Therefore, ONRR continues to be interested in opportunities to further streamline the valuation process, while also bringing added transparency to the system. In particular, we seek ideas and comments on: 1. The potential for creating standardized “schedules” for transportation and processing allowances to reduce the need to rely on case-by-case operator reporting and agency review of actual costs. 2. Opportunities to more fundamentally reassess how non-arm's length transactions are treated for the purposes of determining royalties owed. ONRR recognizes that the costs and benefits of making further changes to its valuation regulations (beyond those specifically proposed in this rule) will depend on the specific commodity at issue ( i.e., oil, gas or coal), as well as geographic or other factors. Thus, detailed comments that elaborate on specific situations where further valuation changes should be considered would be particularly useful to ONRR as it proceeds with this rulemaking as well as any future rules that may be considered. II. Explanation of Proposed Amendments Based on comments ONRR received on the ANPRs and at the public workshops, and other relevant information, we propose this consolidated rule to improve the current regulations to ensure greater clarity, efficiency, certainty, and consistency in production valuation. The general consensus of comments received on the ANPR about arm's-length oil sales was that actual proceeds are the best indicator of value, and ONRR should not change to index prices. Most commenters agreed the valuation methodology for non-arm's-length sales of Federal oil is working, as is using actual costs to determine transportation allowances. Thus, ONRR is not currently proposing major changes to oil valuation methodologies except to eliminate both unused valuation options, such as tendering, and associated definition(s), and to make the oil rule consistent with our proposed changes to the proposed Federal gas rule. The comments we received regarding gas produced from Federal leases were, in certain instances, polarized. Very large companies generally support index pricing as an option if it is revenue-neutral and there are no required true-ups (end-of-year comparison of the index value to actual sales and payment on the higher of the two). Independent gas producers and States generally disagreed with the major companies and did not support index pricing because they believe it may not reflect actual value and may not be revenue neutral. The majority of respondents generally support using actual costs for gas transportation and processing deductions to maintain revenue neutrality. In response, ONRR proposes no major changes for the valuation of arm's-length gas sales. However, for non-arm's-length gas sales, ONRR proposes to eliminate current benchmarks (a series of indicators of market value). Instead, ONRR proposes valuation methodology options based on how gas is sold using the first arm's-length-sale price (affiliate resales), optional index prices, or weighted average pool prices. The general consensus of ANPR commenters for coal valuation was not to change royalty valuation of arm's-length sales and not to use coal index values because of their very limited applicability. Commenters suggested modifying the non-arm's-length coal benchmarks and eliminating seldom-used benchmarks. Commenters agreed ONRR should keep Federal and Indian rules separate. Therefore, at this time, ONRR is proposing no changes to the valuation of arm's-length coal sales. For non-arm's-length coal sales, ONRR proposes to eliminate the current benchmarks. Instead, ONRR proposes to value coal on the gross proceeds received from the first arm's-length sale. ONRR also proposes to value sales of coal between coal cooperative members using the first arm's-length sale or a netback methodology. In addition, if there is no coal sale, and lessees or their affiliates use the coal to generate electricity and sell the electricity, then ONRR proposes to value the coal for royalty purposes based on the gross proceeds the lessee or its affiliate receive for the power plant's arm's-length sales of the electricity, less applicable deductions. ONRR proposes the same changes for both Federal and Indian coal, with some minor exceptions, but would continue to maintain separate regulations. ONRR also proposes other changes to our regulations, although we did not specifically request comments on these changes in the ANPRs or at the workshops. One such proposed change is adding a new “default provision” to address valuation when ONRR determines (1) a contract does not reflect total consideration, (2) the gross proceeds accruing to you or your affiliate under a contract do not reflect reasonable consideration due to misconduct or breach of the duty to market for the mutual benefit of the lessee and the lessor, or (3) it cannot ascertain the correct value of production because of a variety of factors, including, but not limited to, a lessee's failure to provide documents. In these cases, the Secretary may enforce his/her authority and exercise considerable discretion to establish the reasonable value of production using a variety of discretionary factors and any other information the Secretary believes is appropriate. Finally, we rewrote all sections of the current regulations in Plain Language to meet the criteria of Executive Orders 12866 and 12988 and the Presidential Memorandum of June 1, 1998, and to make our rules more clear, consistent, and readable. All citations to the current ONRR regulations in title 30 of the Code of Federal Regulations (CFR) in this preamble refer to the July 1, 2012, CFR. III. Section-by-Section Analysis Before reading the additional explanatory information below, please turn to the proposed rule language that immediately follows the List of Subjects in 30 CFR parts 1202 and 1206 and signature page in this proposed rule. The Department will codify this language in the CFR if we finalize the proposed rule as written. After you read the proposed rule, please return to the preamble discussion below. The preamble contains more information about the proposed rule, such as why we define a term in a certain manner and why we chose one valuation method over another. The derivation table below only shows a crosswalk of the recodified sections of the current and the proposed regulations in part 1206. Derivation Table for Part 1206 The requirements of section: Are derived from section: Subpart C 1206.20 1206.101; 1206.151; 1206.251; 1206.451. 1206.101 1206.102. 1206.102 1206.103. 1206.103 1206.104. 1206.106 1206.105. 1206.107 1206.106. 1206.108 1206.107. 1206.109 1206.108. 1206.110 1206.109. 1206.111 1206.110. 1206.112 1206.111. 1206.113 1206.112. 1206.114 1206.113. 1206.115 1206.114. 1206.116 1206.115. 1206.117 1206.116. 1206.118 1206.117. Subpart D 1206.140 1206.150. 1206.141(a)(1)-(4) 1206.152(a)(1). 1206.141(b)(1)-(3) 1206.152(a)(2). 1206.141(b)(4) 1206.152(b)(1)(iv). 1206.142(a)(4) 1206.153(a)(1). 1206.142(b) 1206.153(a)(2). 1206.142(c) 1206.153(b)(1)(i). 1206.143(a)(1) and (b) 1206.152(b)(1)(ii); 1206.153(b)(1)(ii). 1206.143(a)(2) 1206.152(f); 1206.153(f). 1206.143(c) 1206.152(b)(1)(iii); 1206.153(b)(1)(iii). 1206.144 1206.152(c)(1)-(3); 1206.153(c)(1)-(3). 1206.145 1206.152(e)(1) and (2); 1206.153(e)(1) and (2); 1206.157(c)(1)(ii) and (c)(2)(iii); 1206.159(c)(1)(ii) and (c)(2)(iii). 1206.146 1206.152(i); 1206.153(i). 1206.147 1206.152(k); 1206.153(k). 1206.148 1206.152(g); 1206.153(g). 1206.149 1206.152(l); 1206.153(l). 1206.150 1206.154. 1206.151 1206.155. 1206.152(a) 1206.156(a). 1206.152(b) 1206.156(b); 1206.57(a)(2) and (b)(3). 1206.152(c)(1) 1206.157(a)(2) and (b)(4). 1206.152(f) 1206.157(a)(4). 1206.153(b) 1206.157(f). 1206.153(c) 1206.157(g). 1206.154(a) 1206.157(b). 1206.154(e)-(h) 1206.157(b)(2)(i)-(iii). 1206.154(i) 1206.157(b)(2)(iv). 1206.154(i)(3) 1206.157(b)(2)(v). 1206.155 1206.157(c)(1)(i), (ii). 1206.156 1206.157(c)(2)(i)-(iv). 1206.157(a)(1) and (c) 1206.156(d). 1206.157(a)(2) and 1206.158 1206.157(e). 1206.159(a)(1) 1206.158(a). 1206.159(b) 1206.158(b). 1206.159(c)(1) and (2) 1206.158(c)(1) and (2). 1206.159(d) 1206.158(d)(1). 1206.160 1206.159(a). 1206.161 1206.159(b). 1206.162 1206.159(c)(1). 1206.163 1206.159(c)(2). 1206.164 1206.159(d). 1206.165 1206.159(e). Subpart F 1206.250 1206.250. 1206.251 1206.254; 1206.255; 1206.260. 1206.252(d) 1206.258(a); 1206.261(b). 1206.260(a)(1) and (b) 1206.261(a). 1206.260(c)(2) 1206.261(a)(2). 1206.260(d) 1206.261(c)(3). 1206.260(e) 1206.261(c)(1), (c)(2), and (e). 1206.260(f) 1206.262(a)(4). 1206.260(g) 1206.262(a)(2) and (a)(3). 1206.261 1206.262(a)(1). 1206.262 1206.262(b). 1206.263 1206.262(c)(1). 1206.264 1206.262(c)(2). 1206.265 1206.262(d). 1206.266 1206.262(e). 1206.267(a) 1206.258(a). 1206.267(b)(2) 1206.258(c); 1206.260. 1206.267(c) 1206.259(a)(4). 1206.267(d) 1206.259(a)(2) and (a)(3). 1206.267(e) 1206.258(e). 1206.268 1206.259(a)(1). 1206.269 1206.259(b). 1206.270 1206.259(c)(1). 1206.271 1206.259(c)(2). 1206.272 1206.259(d). 1206.273 1206.259(e). Subpart J 1206.450 1206.450. 1206.451 1206.453; 1206.454; 1206.459. 1206.460 1206.461(a)(1). 1206.463 1206.461(c). A. Section-By-Section Analysis of 30 CFR Part 1202—Royalties, Subpart F—Coal ONRR proposes to amend subpart F regarding Federal and Indian coal production volumes on which you must pay royalties. The proposed rule merely moves current 30 CFR 1206.253 and 1206.452 to 30 CFR part 1202, subpart F to a new § 1202.251. We also rewrote the current sections in Plain Language without substantive change. B. Section-By-Section Analysis of 30 CFR Part 1206—Product Valuation, Subpart A—General Provisions and Definitions, Subpart C—Federal Oil, Subpart D—Federal Gas, Subpart F—Federal Coal, and Subpart J—Indian Coal ONRR proposes to amend subparts A, C, D, F, and J relating to the valuation of oil and gas produced from Federal leases and coal produced from Federal and Indian leases. Subpart A—General Provisions 1206.20 What definitions apply to subparts C, D, F, and J? ONRR proposes to consolidate the definitions from Federal Oil (30 CFR 1206.101), Federal Gas (30 CFR 1206.151), Federal Coal (30 CFR 1206.251), and Indian Coal (30 CFR 1206.451). The consolidated definitions reside in a proposed § 1206.20 under proposed Subpart A—General Provisions and Definitions. ONRR proposes to consolidate the existing definitions for these products to provide greater clarity and eliminate redundancy. Where common terms exist in the four subparts, ONRR modifies the definitions to incorporate the active voice and to use plain and simple language similar to the language reflected in the 2000 Federal crude oil rule. For example, the term arm's-length contract applies the modern language of the 2000 Federal crude oil rule and extends its applicability to Federal gas and Federal and Indian coal. Where a definition has different meanings for different subparts, we define the term for each subpart in that definition. For example, see the definition of “gross proceeds” below. Terms we currently reference in only one subpart, for example ANS (Alaska North Slope), remain unmodified, except we propose to locate these definitions in the consolidated definitions in § 1206.20. Finally, ONRR proposes to add new definitions. We identify all new definitions in the table below and show if each existing definition remains unchanged, is modified, or is eliminated. Summary of Terms and Status Term Status Modified Not modified Added new definition Removed definition Ad valorem lease X Affiliate X Allowance X ANS X Area X Arm's-length contract X Audit X BIA X BLM X BOEM X BSEE X Coal X Coal cooperative X Coal washing X Compression X Condensate X Constraint X Contract X Designee X Exchange agreement X FERC X Field X Gas X Gas plant products X Gathering X Geographic region X Gross proceeds X Index X Index pricing point X Index zone X Indian allottee X Indian Tribe X Individual Indian mineral owner X Keepwhole contract X Lease X Lease products X Lessee X Like quality X Like quality coal X Like-quality lease products X Location differential X Market center X Marketable condition X Marketing affiliate X Mine X Minimum royalty X Misconduct X Net-Back method X Net output X Net profit share X Netting X NGLs X NYMEX price X Oil X ONRR X ONRR-approved commercial price bulletin X ONRR-approved publication X Outer Continental Shelf X Payor X Person X Posted price X Processing X Processing allowance X Prompt month X Quality differential X Region X Residue gas X Rocky Mountain Region X Roll X Sale X Sales type code X Section 6 lease X Short ton X Spot market price X Spot price X Spot sales agreement X Tendering program X Tonnage X Trading month X Transportation allowance X Warranty contract X Washing allowance X WTI differential X We explain the new and modified terms and definitions below. For most modified terms, we rewrote the terms in Plain Language and make no substantive change. Subpart C—Federal Oil 1206.100 What is the purpose of this subpart? This proposed section is the same as current 30 CFR 1206.100. 1206.101 How do I calculate royalty value for oil I or my affiliate sell(s) under an arm's-length contract? This proposed section is the same as current 30 CFR 1206.102 except for two substantive changes. First, proposed paragraph (a) contains the same provisions as existing § 1206.102(a) with one modification. Proposed paragraph (a) adds that the value in this paragraph does not apply “if ONRR decides to value your oil under § 1206.105.” Proposed § 1206.105 is ONRR's new proposed default valuation mechanism. ONRR also proposes to add a new provision to paragraph (c)(1) allowing ONRR to decide a lessee's oil value if the lessee fails to make the election in this paragraph. Under the current regulations, if a contract is either non-arm's-length or an exchange agreement, a lessee can choose one of two different valuation methods. ONRR proposes to add a new provision to clarify the current regulations by explaining the consequences if a lessee fails to properly make the election. For example, if a lessee improperly classifies its contract as an arm's-length contract under the current regulations, the lessee will most likely pay royalties on the price specified in its contract. However, if the lessee or ONRR subsequently determines the contract actually was non-arm's-length or an exchange agreement, the existing regulations do not specify if the lessee may make the election retroactively. To remove this ambiguity, ONRR proposes to eliminate the lessee's election in these situations and provide that ONRR can determine the lessee's oil value under the new default valuation mechanism in § 1206.105. 1206.102 How do I value oil not sold under an arm's-length contract? This proposed section is the same as current 30 CFR 1206.103 except for two substantive changes. The first substantive change is to paragraph (a), which explains when you may value oil under this section. Proposed paragraph (a) requires you to use this section to value your oil “unless ONRR decides to value your oil under § 1206.105.” Proposed § 1206.105 is ONRR's new proposed default valuation mechanism. ONRR also proposes to remove current 30 CFR 1206.103(b)(1) containing the option for lessees to use a tendering program to value oil they produce from Federal leases in the Rocky Mountain Region. Since the final oil valuation regulations were published in March 2000, ONRR is aware of only one company that valued its oil using this provision. At that time, we received feedback from oil producers that it was administratively inefficient to implement a tendering program for valuation purposes. We do not believe any oil producer has used this provision since then. Therefore, because industry has abandoned its use of this provision, we propose to remove tendering from the options available to value Federal oil produced in the Rocky Mountain Region. Finally, ONRR proposes to amend paragraphs (d) and (e) of § 1206.103 in the current regulations. Under the current regulations, lessees may apply paragraphs (d) and (e) to value their production with ONRR approval. ONRR proposes to amend paragraphs (d) and (e) to instead state that ONRR may decide to use these paragraphs to value production under § 1206.105. 1206.103 What publications are acceptable to ONRR? The substantive requirements of this proposed section are the same as current 30 CFR 1206.104. However, we propose to remove our requirement to publish a notice of acceptable publications in the Federal Register . Instead, we propose to provide acceptable publications on our Web site. 1206.104 How will ONRR determine if my royalty payments are correct? In this section, ONRR proposes amendments to the text of its gross proceeds provisions to rewrite them in Plain Language and to make them consistent with other valuation regulations. Thus, rather than repeat the requirements or procedures in each applicable section of this rule, ONRR proposes to have this section apply to this entire subpart. However, the substantive requirements of proposed paragraphs (d), (e) and (f) remain unchanged. We propose the same changes to the Federal gas amendments that we propose in this section, so please refer to the discussion of the substantive changes we propose to make to the Federal gas regulation in § 1206.143 below for more information. 1206.105 How will ONRR determine the value of my oil for royalty purposes? ONRR proposes to add a new “default” valuation § 1206.105 under which ONRR can value your oil if we decide to do so pursuant to the criteria under § 1206.104 or any other provision in this subpart. If ONRR determines value under this new default section, we may consider any information we deem relevant. Also, this proposed section enumerates factors ONRR may consider if we decide we will determine value, for royalty purposes, under this section, which may include, but not be limited to: (a) The value of like-quality oil in the same field or nearby fields or areas; (b) The value of like-quality oil from the same plant; (c) Public sources of price or market information ONRR deems reliable; (d) Information available and reported to ONRR, including but not limited to, on Form ONRR-2014 and Form ONRR-4054; (e) Costs of transportation or processing, if ONRR determines they are applicable; or (f) Any information ONRR deems relevant regarding the particular lease operation or the salability of the oil. This proposed section allows ONRR to consider any criteria we deem relevant, as well as criteria similar to the current gas valuation benchmarks under 30 CFR 1206.152(c)(1) and (2) and 1206.153(c)(1) and (2). Like the valuation regulations in effect prior to the 1988 rulemaking that resulted in the current gas valuation regulations, 30 CFR 206.103 (1984) (onshore) and 206.150 (1984) (offshore), under proposed § 1206.105, ONRR has the authority and responsibility to establish the reasonable value of production for royalty purposes and possesses considerable discretion in determining that value. Independent Petroleum Ass'n v. DeWitt, 279 F.3d at 1039-1040, and cases cited therein. Thus, under this proposed section, ONRR has broad authority to value your oil in the manner we deem most appropriate considering the factors we deem most appropriate. We add the same default provision to Federal gas in § 1206.144, Federal coal in § 1206.254, and Indian coal in § 1206.454. 1206.106 What records must I keep to support my calculations of value under this subpart? 1206.107 What are my responsibilities to place production into marketable condition and to market production? The two proposed sections above are the same as current 30 CFR 1206.105 and 1206.106, except we rewrite the sections in Plain Language. 1206.108 How do I request a value determination? This proposed section is the same as current 30 CFR 1206.107 except we make some substantive changes to provide greater clarity to the process a lessee may use to request valuation guidance and determinations, as well as the effect of ONRR's response to such requests. Because we are making the same changes to the Federal gas amendments in this proposed rulemaking, please refer to proposed § 1206.148 of the Federal gas regulation below for more information. 1206.109 Does ONRR protect information I provide? This proposed section is the same as current 30 CFR 1206.108, except we rewrite the section in Plain Language. 1206.110 What general transportation allowance requirements apply to me? This proposed section is the same as current 30 CFR 1206.109 except we reword the section name and make the following substantive changes. First, in proposed paragraph (a)(2)(ii), we add a new provision that states you may not take a transportation allowance for the movement of oil produced on the OCS from the wellhead to the first platform. Because we are making the same change to the Federal gas amendments we propose in this rulemaking, please refer to § 1206.152(a)(2)(ii) of the Federal gas regulation below for more information. Second, we propose in paragraph (b) to clarify that if you request to use a different cost allocation than that in paragraph (b), and we approve your request, you can only use your proposed allocation methodology prospectively. We make this proposed change to clarify that you may not request retroactive changes to your royalty reporting and payment. We make the same change to proposed §§ 1206.112(b), 1206.112(i)(1), 1206.112(j), 1206.113(c)(2), 1206.150(c)(4), 1206.152(b), 1206.154(b)(3), 1206.154(i)(1), 1206.161(b)(3), 1206.151(h)(1), 1206.262(b)(3), 1206.262(h)(1), 1206.269(b)(3), 1206.269(h)(1), 1206.462(b)(3), 1206.462(h)(1), 1206.463(d)(4)(i), 1206.469(b)(3), 1206.469(h)(1), and 1206.470(d)(4)(i). Third, in paragraph (d)(1) of this section, we propose to remove current 30 CFR 1206.109(c)(2) that allows a lessee to request to exceed the limit on transportation allowances of 50 percent of the value of the oil. We also propose to terminate existing approvals to exceed the 50 percent limit under paragraph (d)(2). Because we are making the same change to the Federal gas amendments in this proposed rulemaking, please refer to § 1206.152(e) below for more information. Fourth, like the default provision for valuation we discuss above under § 1206.104, proposed paragraph (f) provides that ONRR may determine your transportation allowance under § 1206.105 if (1) there is misconduct by or between the contracting parties, (2) the total consideration the lessee or its affiliate pays under an arm's-length contract does not reflect the reasonable cost of transportation because the lessee breached its duty to market oil for the mutual benefit of the lessee and the lessor by transporting oil at a cost that is unreasonably high, or (3) ONRR cannot determine if the lessee properly calculated a transportation allowance for any reason. Because we are making the same change to the Federal gas amendments we propose in this rulemaking, please refer to the discussion of § 1206.152(g) below for more information on this provision. Finally, we also propose a new provision under paragraph (g) to clarify that you do not need ONRR's approval before reporting a transportation allowance for costs you incur. This is consistent with existing practice. 1206.111 How do I determine a transportation allowance if I have an arm's-length transportation contract? This proposed section is the same as current 30 CFR 1206.110, except for three substantive changes. ONRR proposes to eliminate the provision in current 30 CFR 1206.110(b)(4) that allows a lessee to include the costs of carrying line fill on its books as a component of arm's-length transportation allowances. Rather, we propose to specifically preclude including this cost in transportation allowances under new paragraph (c)(9) of this section. We propose to eliminate allowing this cost because we believe this is a cost to market the oil we disallow as a deduction under our existing valuation regulations. Line fill occurs after the royalty measurement point and is necessary for the pipeline operator to get Federal oil production to market. We request comments on whether this is a marketing cost. We also propose to add a new paragraph (d) that applies if you have no contract in writing for the arm's-length transportation of oil. In that case, ONRR determines your transportation allowance under § 1206.105. Under the proposed rule, you may propose to ONRR a method to determine the allowance using the procedures in § 1206.108(a) and may use that method to determine your allowance until ONRR issues its determination. This proposed paragraph does not apply if a lessee performs its own transportation. Instead, proposed § 1206.112 for non-arm's-length transportation allowances, applies. Finally, ONRR proposes to eliminate the provision in current 30 CFR 1206.110(g) that allows a lessee to report transportation costs, in certain circumstances, as a transportation factor. We propose that a lessee must report separately all transportation costs under both arm's-length and non-arm's-length sales contracts as a transportation allowance on Form ONRR-2014. ONRR believes requiring lessees to report all deductions for transportation costs separately as allowances on Form ONRR-2014 is more transparent, supports ONRR's increased data mining efforts to promote accurate upfront royalty reporting, and assists State and Federal auditors in their compliance work. 1206.112 How do I determine a transportation allowance if I do not have an arm's-length transportation contract? This proposed section is the same as current 30 CFR 1206.111 except for the following substantive changes. We replace current 30 CFR 1206.111(b)(3) and (b)(4) with proposed paragraph (b)(3)(i) of this section, which allows you to elect to calculate depreciation and a return on undepreciated capital investment in a transportation system under proposed paragraph (b)(3)(i)(1) or a return on undepreciated capital investment with no depreciation under proposed paragraph (b)(3)(i)(2). The proposed regulation provides that once you make an election, you may not change it without ONRR's approval. In addition, proposed paragraph (b)(3)(ii) replaces current 30 CFR 1206.111(b)(5). Currently, 30 CFR 1206.111(b)(5) allows you to continue deducting 10 percent of the cost of capital expenditures once you have depreciated the asset below 10 percent under current 30 CFR 1206.111(j). However, under proposed paragraph (i)(1)(iii) of this section, instead of allowing a 10 percent deduction, we base the return on undepreciated capital investment on the reasonable salvage value of the asset. ONRR believes this method more reasonably reflects the actual costs for oil transportation systems. Also, it makes the treatment of depreciation consistent with other royalty valuation rules, including the current Federal gas rule at 30 CFR 1206.157(g) (proposed § 1206.154(i)). In proposed paragraph (c)(2)(ii), we prohibit you from including actual or theoretical line loss as a transportation cost. ONRR proposes to eliminate the provision in the current regulations at 30 CFR 1206.111(b)(6)(v) which allows a lessee to reduce the royalty volume measured at the royalty measurement point by actual or theoretical line loss occurring after the royalty measurement point. This change is consistent with long-standing mineral leasing laws that require royalty on the volume of production removed from the lease. Mineral Leasing Act, 30 U.S.C. 181-287; Mineral Leasing Act for Acquired Lands, 30 U.S.C. 351-359 (onshore acquired lands); Indian leasing statutes, 25 U.S.C. 396a—396g (tribal leases); 25 U.S.C. 396 (allotted leases); and the Outer Continental Shelf Lands Act, 43 U.S.C. 1331-1356. This change also makes Federal oil valuation consistent with ONRR's other product valuation regulations. Under proposed paragraph (c)(2)(iii), ONRR eliminates the provision in current 30 CFR 1206.111(b)(6)(ii) which allows a lessee to include the costs of carrying line fill on its books as a component of non-arm's-length transportation allowances. We believe this is a cost to market the oil, which we disallow as a deduction under current valuation regulations. Line fill occurs after the royalty measurement point and is necessary for the pipeline operator to get Federal oil production to market. We request comments on whether this is a marketing cost. Proposed paragraph (i)(1) allows you to calculate depreciation and a return on undepreciated capital investment using either a straight-line method (based on either the life of the equipment or the life of the reserves that the transportation system services) or a unit of production method. This depreciation method was in ONRR's oil valuation regulations in effect for producer-owned transportation systems prior to the effective date of the 2000 Federal oil valuation regulations. This new proposed paragraph (i)(1) would replace the provision in current 30 CFR 1206.111(h), which allows a lessee to depreciate a transportation asset a second time after the lessee already fully depreciated that asset. The current Federal oil valuation regulations authorize fully depreciated transportation assets to be recapitalized a second time when they are purchased from the original owner. ONRR proposes to remove this provision. Under proposed paragraph (i)(1)(ii), ONRR allows depreciation of pipeline assets only one time. If the pipeline asset is sold, we allow the purchaser to continue the remaining allowance depreciation schedule if applicable. This change makes Federal oil valuation consistent with ONRR's other product valuation regulations. Proposed paragraph (i)(1)(iii)(B) changes the return on undepreciated capital investment from10 percent to the reasonable salvage value of the asset multiplied by the rate of return in proposed paragraph (i)(3) of this section. New proposed paragraph (i)(2) provides an alternative to depreciating the asset under paragraph (i)(1). Under this option, you may elect to use a cost equal to the allowable initial capital investment in the transportation system, multiplied by the rate of return in proposed paragraph (i)(3) of this section. If you chose this option, you may not include depreciation as a cost in your allowance. ONRR removed the provision limiting this option to transportation assets put in place after March 1, 1988. When ONRR published its Federal oil valuation regulations on May 5, 2004, it changed the requirements for transportation allowances. In recognition that certain transportation facilities had been given approval prior to these regulations' effective date (August 1, 2004), ONRR made the new requirements apply only to facilities that were placed in service on or after the effective date of these regulations. Now, almost ten years later, ONRR believes that none of facilities affected by the 2004 rule change are still eligible for depreciation under the requirements in effect prior to August 1, 2004. Therefore, we remove this language from the proposed regulations. Proposed paragraph (i)(3) would amend current 30 CFR 1206.111(i)(2) to change the Standard & Poor's BBB bond rate we allow as an approximation of the cost of capital for non-arm's-length transportation. Currently, 30 CFR 1206.111(i)(2) allows a lessee to compute the rate of return on the undepreciated cost of capital by multiplying the undepreciated amount remaining by 1.3 times the Standard & Poor's BBB bond rate. ONRR proposes to decrease the multiplier of the Standard & Poor's BBB bond rate from 1.3 to 1.0. In the final Federal oil valuation regulations published in March 2000, we increased the multiplier of the Standard & Poor's BBB bond rate from 1.0 to 1.3. We propose to change it back to 1.0 times the BBB bond rate because we believe this rate better reflects the cost of borrowing to finance capital expenditures involved in pipeline construction. It also is consistent with our other product valuation regulations. When a company or affiliate invests in shipping its own production, it considers if it can more profitably transport its own production or contract with a third party to provide the service. At this stage in production development, a company has a solid asset to demonstrate its ability to repay the capital investment necessary to construct the pipeline. ONRR consulted with FERC and has concluded that the BBB bond rate is an adequate representation for the cost of capital for the construction of producer-owned pipelines. 1206.113 What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices? 1206.114 How will ONRR identify market centers? 1206.115 What are my reporting requirements under an arm's-length transportation contract? Proposed §§ 1206.113 through 1206.115 are the same as current 30 CFR 1206.112 through 1206.114, but we rewrite the sections in Plain Language and update the examples in current 30 CFR 1206.112(d) using November 2012 prices. 1206.116 What are my reporting requirements under a non-arm's-length transportation contract? This proposed section is the same as current 30 CFR 1206.115 except we make each sentence a paragraph. We also add a new paragraph (d) that explains you must follow the reporting requirements for arm's-length contract under § 1206.115 if you are authorized under § 1206.112(j) to not use your actual costs. 1206.117 What interest and penalties apply if I improperly report a transportation allowance? This proposed section is the same as current 30 CFR 1206.116 except we make each sentence a paragraph and add “penalties” to the heading to better describe the section. 1206.118 What reporting adjustments must I make for transportation allowances? 1206.119 How do I determine royalty quantity and quality? These two proposed sections, 30 CFR 1206.118 and 1206.119, are the same as current §§ 1206.117 and 1206.119, respectively, but we rewrite the sections in Plain Language. 1206.120 How are operating allowances determined? We propose to remove current 30 CFR 1206.120 on how to determine operating allowances because it is unnecessary. If a lease has provisions for operating allowances, that lease term will govern valuation under proposed § 1206.100(d)(4) of this subpart. Subpart D—Federal Gas ONRR proposes to add new §§ 1206.140 through 1206.149 to this subpart to codify, clarify, and enhance current ONRR Federal gas valuation practices. 1206.140 What is the purpose and scope of this subpart? We propose to redesignate the current regulations at § 1206.150 to § 1206.160. Also, in this proposed rule, we rewrote the redesignated sections in Plain Language. Proposed § 1206.140 is the same as current 30 CFR 1206.150 except for three changes. First, we propose to add a new paragraph (b) to explain that the terms “you” and “your” in this subpart refer to the lessee. Second, we propose to redesignate paragraphs (b) and (c) as paragraphs (c) and (d). Finally, we propose to remove existing regulations in paragraph (d), which state this subpart is intended to ensure leases are administered in accordance with governing mineral leasing laws and lease terms. We believe current paragraph (d) is unnecessary and duplicative of our authority to promulgate this rule. 1206.141 How do I calculate royalty value for unprocessed gas I or my affiliate sell(s) under an arm's-length or non-arm's-length contract? This proposed section explains the valuation of unprocessed gas for royalty purposes. Proposed paragraph (a)(1) explains that this section applies to unprocessed gas—meaning gas that is never processed—consistent with the current gas regulations. Proposed paragraph (a)(2) explains this section applies to gas you are not required to value under proposed § 1206.142, or that ONRR does not value under proposed § 1206.144. Proposed § 1206.142(a) explains what gas ONRR considers processed for valuation purposes, and proposed § 1206.144 explains ONRR's new proposed default valuation mechanism. We discuss proposed §§ 1206.142 and 1206.144 below. Under proposed paragraph (a)(3), we state this section also applies to processed gas you must value prior to processing under § 1206.151 of this part. Proposed § 1206.151 contains the dual accounting provisions for Federal gas in current 30 CFR 1206.155. Under proposed paragraph (a)(4), we consider unprocessed gas any gas you sell prior to processing if price is based on an amount per MMBtu or Mcf, and not on the value of residue gas and gas plant products. Therefore, this proposed paragraph applies to the valuation of gas when price is not based on a processed gas price. Paragraph (b) proposes a new valuation methodology based on the first arm's-length sale of the gas. ONRR promulgated the current gas valuation regulations in 1988 to achieve market value based on transactions between independent, non-affiliated parties. The Department has long believed the values established in arm's-length transactions are the best indication of market value, and the 1988 rules reflect that belief. Although the Secretary's responsibility to determine the royalty value of minerals produced has not changed, the industry and marketplace have changed dramatically since we wrote the 1988 regulations. As discussed below, industry and marketplace changes, as well as litigation necessitate changes to ONRR's valuation regulations. Indeed, ONRR already amended the Indian gas (30 CFR part 1206, subpart E) and Federal oil (30 CFR part 1206, subpart C) valuation regulations to simplify those regulations and provide early certainty by valuing those products based on the first arm's-length sale and/or on publicly available prices. When we developed the 1988 rules, producers most commonly sold natural gas at the wellhead to natural gas pipeline companies, which transported and sold the gas to local distribution companies. However, from mid-1980 to early 1990, a series of FERC rulemakings resulted in deregulation of some pipeline systems. As a result, industry now sells directly to end users or distributors, and pipelines only provide transportation services. Producers also created marketing affiliates to which they initially transferred production. For lessee sales to affiliates, the current Federal gas valuation regulations require a lessee to value production based on a series of “benchmarks” to be applied in a prescribed order (30 CFR 1206.152(c)). The first benchmark is the gross proceeds accruing to the lessee in a sale under its non-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 (30 CFR 1206.152(c)(1)). This method has posed practical difficulties since companies are not privy to other companies' “comparable” sales transactions. In addition, ONRR and lessees have found it difficult to determine what portion of lease production a lessee must sell at arm's-length to reliably determine the value of the remaining production. Likewise, the remaining benchmarks at 30 CFR 1206.152(c)(2) and (3) have proven difficult for industry to follow and ONRR to administer. ONRR proposes to replace the current regulations in § 1206.152(c)(1), (2), and (3) with proposed paragraph (b). To simplify and clarify valuation of non-arm's-length sales, proposed paragraph (b) bases value on the first arm's-length sale with applicable allowances. The first arm's-length sale may occur immediately, or may follow one or more non-arm's-length transfers or sales of the gas. However, under the proposed rule, you will use the first arm's-length sale regardless of whether you sell or transfer gas to one or more affiliates or other persons in non-arm's-length transactions before the first arm's-length sale, and regardless of the number of those non-arm's-length transactions. This arm's-length sales value will apply unless you exercise the index-based option in proposed paragraph (c) of this section we discuss below. Proposed paragraph (b)(1) would state value is the gross proceeds accruing to you under an arm's-length contract, less applicable allowances. Similarly, under proposed paragraph (b)(2), if you sell or transfer your Federal gas production to your affiliate, or some other person at less than arm's length, and that person or its affiliate then sells the gas at arm's length, royalty value will be the other person's (or its affiliate's) gross proceeds under the first arm's-length contract. For example, a lessee might sell its Federal gas production to a person who is not an “affiliate” as defined, but with whom its relationship is not one of “opposing economic interests” and therefore is not at arm's length. An illustrative example is when a number of working interest owners in a large field form a cooperative venture that purchases all of the working interest owners' production and resells the combined volumes to a purchaser at arm's-length. Xeno, Inc., 134 IBLA 172 (1995), involved a similar situation. If none of the working interest owners own 10 percent or more of the new entity, the new entity would not be an “affiliate” of any of them. Nevertheless, the relationship between the new entity and the respective working interest owners is not at arm's length because of the lack of opposing economic interests regarding the contract. In this case, we believe it appropriate to value the production based on the arm's-length sale price the cooperative venture receives for the gas. Therefore, under proposed paragraph (b)(2), you must value the production based on the gross proceeds accruing to you, your affiliate, or other person to whom you transferred the gas (or its affiliate) when the gas ultimately is sold at arm's length, unless you elect to use the index pricing option we propose under § 1206.141(c) of this section or ONRR decides to value your gas under the new default valuation provision in proposed § 1206.144 discussed below. In summary, to provide early certainty and simplification, ONRR proposes to amend its valuation regulations for Federal gas to provide that, with certain exceptions, the first arm's-length sale is the value for royalty purposes consistent with valuation of non-arm's-length sales of Federal oil production under current 30 CFR 1206.102(a). Proposed paragraph (b)(3) explains valuation if you, your affiliate, or another person sell under multiple arm's-length contracts for gas produced from a lease that is valued under this proposed paragraph (b). In this case, unless you exercise the index-based option we provide in paragraph (c) of this section, because you sold non-arm's length to your affiliate or another person, under the proposed rule, you must value the gas based on the volume-weighted average of the value established under this paragraph for each contract for the sale of gas produced from that lease. This is identical to current 30 CFR 1206.102(b) applicable to valuation of Federal oil. In addition, we believe this provision is consistent with ongoing practice under the current gas valuation rule. Proposed paragraph (b)(4) contains the provisions of the current gas valuation rule at 30 CFR 1206.152(b)(1)(iv) that explains how to value over-delivered volumes under a cash-out program, but we rewrite this provision in Plain Language. ONRR proposes to add a new paragraph (c) containing an index price valuation methodology that a lessee may elect to use in lieu of valuing its gas under proposed paragraphs (b)(2) and (b)(3) of this section based on the gross proceeds accruing to its affiliate or other person under the first arm's-length sale. The proposed methodology is based on publicly available index prices less a specified deduction to account for processing and transportation costs. Under the proposed rule, this valuation methodology also applies to “no contract” situations we describe below under paragraph (e). We believe this index price option simplifies the current valuation methodology and provides early certainty. Many pipelines and service providers now charge producers “bundled” fees that include both deductible costs of transportation and non-deductible costs to place production into marketable condition. Both ONRR and lessees with arm's-length transportation contracts have found allocating the costs between placing the gas in marketable condition and transportation is administratively burdensome and time consuming. Similarly, when processing plants charge bundled fees that include non-deductible costs, the cost allocation is administratively burdensome and time consuming. Litigation also has complicated the application of ONRR's gas valuation regulations. Although litigation has clarified what constitutes marketable condition, its application is fact specific and time consuming. See Devon and cases cited therein. The proposed index-based option provides a lessee with an alternative that is simple, certain, and avoids the requirements to “trace” production when there are numerous non-arm's-length sales prior to an arm's-length sale and unbundle fees. Under this proposed paragraph (c), the lessee may choose to value its gas only in an area that has an active index pricing point published in a publication that ONRR approves. The lessee may elect to value its gas under this proposed paragraph, and that election is binding on the lessee for 2 years. ONRR would post a list of approved publications at www.onrr.gov . ONRR proposes to use Platts and Natural Gas Intelligence as ONRR-approved publications but invites comments on whether these publications are appropriate, as well as whether there are other publications that ONRR should use. If the lease is in an area with active index pricing points, the lessee must determine the applicable index pricing point or points. We used the language in proposed paragraphs (c)(1)(i) and (ii) “If you can only transport to one index pricing point” and “If you can transport gas to more than one index pricing point,” respectively (emphasis added), because, under the proposed rule, we intend that for an index pricing point to be applicable, the lessee must be able to physically transport its gas by pipeline to that index pricing point. Further, an index pricing point would be applicable as long as the lessee could physically transport their gas by pipeline to that index pricing point (emphasis added). This means that under the proposed rule, the index pricing point applies even if the lessee could not transport its gas to that index pricing point because the pipeline is constrained (for example when all available capacity on a pipeline through which the lessee's gas might flow to that index pricing point was already under contract to other parties). For example, assume you have a lease in the West Delta area of the Gulf of Mexico and your lease is physically connected by pipeline to the Mississippi Canyon Pipeline. In this case, your gas is physically capable of flowing to the Toca Plant (through the Southern Natural Gas Pipeline), the Yscloskey Plant (through the Tennessee Gas Pipeline), or the Venice Plant, and you have multiple index pricing points to which your gas can physically flow. Also, assume the highest reported monthly bid week price among the multiple index pricing points is the Tennessee Gas 500 Leg Price at the tailgate of the Yscloskey Plant. Finally, assume you cannot flow your gas through the Tennessee Gas Pipeline (to the Yscloskey Plant) because all available capacity on that pipeline is under contract to other persons, and the pipeline has no capacity available to you for the production month—in other words, it is constrained. In this example, you would use the highest reported monthly bid week price at the tailgate of the Yscloskey Plant as the value under this paragraph even though your gas did not flow to that index pricing point during the production month. Under proposed paragraph (c), the lessee could not use index pricing points if it could not physically transport its gas to that index pricing point because there is not a pipeline or series of pipelines that physically connect to the lease and flow from the lease to the index pricing point. ONRR would exclude the use of these index pricing points because they do not represent points at which the lessee can sell its gas, and it is difficult to adjust these prices for location differentials between the index pricing points and the lease. If the lessee can transport its gas to only one index pricing point, the value under proposed paragraph (c)(1)(i) is the highest reported monthly bid week price for that index pricing point in the ONRR-approved publication for the production month. If the lessee can transport its gas to more than one index pricing point, the value under proposed paragraph (c)(1)(ii) is the highest reported monthly bid week price for the index pricing points to which the lessee could transport its gas, in the ONRR-approved publication for the production month. However, under paragraph (c)(1)(iii), if there are sequential index pricing points on a pipeline, the lessee would use the first index pricing point at or after the lessee's gas enters the pipeline. ONRR recognizes that index pricing points are normally located off the lease, and frequently at lengthy distances from the lease. Thus, under proposed paragraph (c)(1)(iv), ONRR allows a lessee to reduce the highest reported monthly bid week price by a set amount to account for transportation costs a lessee would incur to move the gas from the lease to an applicable index pricing point. ONRR proposes to allow a lessee to reduce the highest reported monthly bid week prices by 5 percent for sales from the OCS Gulf of Mexico and by 10 percent for sales from all other areas, but not by less than 10 cents per MMBtu or more than 30 cents per MMBtu. ONRR proposes these percent reductions based on the average gas transportation rates that lessees have reported to ONRR from 2007 through 2010 for OCS and all other areas. ONRR proposes to allow a lessee to choose the index price methodology to value its gas under this paragraph for the following reasons: (1) It relies on a market price at which gas is sold from the area during the production month; (2) it recognizes costs that a lessee must incur to transport gas from the lease to an index pricing point; and (3) it makes payment and verification of royalties paid simple and efficient, thereby saving both lessees and ONRR significant administrative costs. Further, ONRR believes this alternative methodology provides ONRR with a reasonable market value for the lessee's gas that avoids requiring a lessee and ONRR to track every resale of the lessee's gas during the production month, especially when those sales can involve several transactions hundreds of miles downstream from the lease. As we state above, it also avoids the unbundling of transportation and processing costs. ONRR proposes to use the highest reported monthly bid week price with a reduction for transportation costs. We propose this because it generally represents the gross proceeds net of transportation allowances accruing to lessees that ONRR believes are most likely to choose this option to value their gas based on information lessees and others reported on Form ONRR-2014 for the period from 2007 through 2011. Proposed paragraph (c)(1)(v) states that, after you select an ONRR-approved publication available at www.onrr.gov, you may not select a different publication more often than once every 2 years. ONRR also proposes, under paragraph (c)(1)(vi), to exclude individual index prices from this option if we determine that the index price does not accurately reflect the value of production. ONRR plans to disallow the use of index prices with low liquidity, such as those classified as Tier 3 in the Platts publications. ONRR would post a list of excluded index pricing points at www.onrr.gov . We would appreciate comments on this proposal. Proposed paragraph (c)(2) explains that you may not take any other deductions from the value calculated under this paragraph (c) because you would already receive a reduction for transportation under proposed paragraph (c)(1)(iv). Proposed paragraph (d)(1) provides that, if you have no written contract or no sale of gas subject to this section and there is an index pricing point for the gas, then you must value your gas under the index pricing provisions of paragraph (c) of this section unless ONRR values your gas under § 1206.144. This provision includes, but is not limited to, when: (1) The lessee sells its gas to an affiliate and the affiliate uses the gas in its facility; (2) the lessee sells its gas to an affiliate and the affiliate resells the gas to another affiliate of either the lessee or itself and that affiliate uses the gas in its facility; (3) the lessee uses the gas as fuel for its other leases in the field or area; or (4) the lessee delivers gas to another person as payment of an overriding royalty interest that other person holds. Proposed paragraph (d)(2) addresses situations in which you have no contract for the sale of gas subject to this section and there is not an index pricing point for the gas. In these situations, ONRR will decide the value under § 1206.144. However, when this occurs, under paragraph (d)(2)(i), we require that you propose to ONRR a method to determine the value using the procedures in proposed § 1206.148(a). Proposed § 1206.148(a) describes the information you must provide to ONRR when you request a valuation determination. Proposed paragraph (d)(2)(ii) allows you to use your proposed method until ONRR issues a decision. After ONRR issues a determination, under paragraph (d)(2)(iii), you will have to make any adjustment under proposed § 1206.143(a)(2). You have to make adjustments only if ONRR decides you must use a different methodology than you propose under paragraph (d)(2)(i). 1206.142 How do I calculate royalty value for processed gas I or my affiliate sell(s) under an arm's-length or non-arm's-length contract? ONRR proposes a new § 1206.142 including a new paragraph (a) that amends and expands what is processed gas for royalty valuation purposes. Currently, when gas is sold under an arm's-length contract prior to processing, and the lessee neither retains nor exercises any rights to the gas after processing (in other words, an outright sale before the plant), such gas is valued as unprocessed gas. Included are contracts where the title passes before processing, but payment is based on the values of residue gas and gas plant products after processing. Percentage-of-Proceeds (POP) contracts (contracts 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) are the most common of these contracts, but ONRR has observed a myriad of variations of such contracts. Because this gas is valued as unprocessed gas under the current regulations, there are no limits on the minimum value of such gas for royalty purposes, except for gas sold under arm's-length POP contracts, which has a minimum value of 100 percent of the residue gas. No such limitation applies to contracts that do not specifically qualify as POP contracts. For example, if the sales value is based on a percentage of an index price for residue gas and/or NGLs, the current regulations base value simply on the gross proceeds the lessee receives under the contract. In essence, the unprocessed gas regulations allow such sales arrangements to reduce the value of residue gas below the 100-percent minimum value required under the processed gas regulations and below the 1-percent minimum value for NGLs (assuming ONRR approves an exception under the current rules in excess of 66 2/3 percent of the NGL value) required for processed gas. ONRR has seen numerous contract arrangements that provide payment terms based on: (1) A percentage of the volume or value of residue gas, plant products, or any combination of the two actually recovered at the plant; (2) the full volume and value of residue gas and/or plant products recovered at the plant, less a flat fee per MMBtu of wet gas entering the plant; (3) a combination of (1) and (2); and (4) the value of a percentage of the theoretical volumes of residue gas and/or plant products contained in the wet gas stream (so-called casing head gas contracts). Because the many contract variations base the underlying value on processed gas values, ONRR believes we should require a lessee to value gas sold under such contracts as processed gas for royalty purposes. This proposal provides the protection the current processed gas regulations have against excessive transportation and processing allowances and prevents a lessee from structuring contracts to avoid these requirements. Such a change also clarifies if gas is processed gas or unprocessed gas. In summary, under proposed paragraph (a)(1), ONRR will consider gas you or your affiliate do not sell or otherwise dispose of under an arm's-length contract before processing “processed gas.” Paragraph (a)(1) also applies to non-arm's-length sales of gas before processing and transfers to a plant without a contract like the current regulations. Proposed paragraph (a)(2) applies to the situations described above when payment is based on any constituent products resulting from processing, such as residue gas, NGLs, sulfur, or carbon dioxide. We would value POP contracts, percentage-of-index contracts, casing head gas contracts, and contracts with any such variations of payment based on volumes or value of those products as processed gas. With the exception of POP contracts, this constitutes a departure from current practice. Proposed paragraph (a)(3), while not a change in current regulatory practice, explicitly states that the lessee must value gas processed under a keepwhole contract as processed gas. Under proposed § 1206.20, we define a keepwhole contract as a processing agreement under which the processor compensates the lessee by delivering to the lessee a quantity of residue gas after processing equivalent to the quantity of gas the processor received prior to processing, normally based on heat content, less gas used as plant fuel and gas that is unaccounted for and/or lost. The lessee does not receive NGLs under these contracts. Over the past several years, ONRR has witnessed much confusion over how to value gas sold under such contracts for royalty purposes. This provision makes it clear that the lessee must value gas processed under a keepwhole contract as processed gas. That is, royalty would be based on 100 percent of the value of residue gas, 100 percent of the value of gas plant products, plus the value of any condensate recovered downstream of the point of royalty settlement prior to processing, less applicable transportation and processing allowances. To illustrate how to calculate the processing allowance in these cases, assume you deliver 32,000 MMBtu of natural gas to the gas processing plant. Also assume 7,000 MMBtu represents the shrinkage volume (the MMBtu equivalent of the NGLs recovered), and the plant recovers and retains 92,000 gallons of NGLs from your gas. Further, assume the plant returns 7,000 MMBtu of gas to you at the tailgate of the plant in addition to the residue gas that results after processing your gas to “keep you whole.” Finally, assume the 7,000 MMBtu of gas returned to you is worth $42,000 and the NGLs the plant retained are worth $63,000. In this example, the cost you incur to process the gas is $21,000 ($63,000−$42,000). If you incur additional costs, for example a $0.03 per MMBtu fee times the 32,000 MMBtu you deliver to the plant for processing, then you add those additional costs (in this example, $960) to the $21,000 cost calculated above to determine your total processing costs (in this example $21,960). Proposed paragraph (a)(4) simply restates current 30 CFR 1206.153(a)(1) regarding arm's-length contracts and reservations of rights to process gas the lessee or its affiliate exercises. ONRR also proposes paragraph (b), which contains the same requirements as current 30 CFR 1206.153(a)(2), but we rewrite it in Plain Language, without substantive change. Like the valuation of unprocessed gas under proposed § 1206.141(b), proposed paragraph (c) provides that the value of residue gas or any gas plant product under this section is the gross proceeds accruing to you or your affiliate under the first arm's-length contract. Also, like proposed § 1206.141(b), this value does not apply if you exercise the index-based option we provide in paragraph (d) of this section or if ONRR decides to value your residue gas or any gas plant product under the new default valuation provision in § 1206.144. Proposed paragraphs (c)(1), (2), (3), and (4) explain to which transactions this paragraph applies. See the discussion of the identical proposal for proposed §§ 1206.141(b)(1), (2), (3), and (4) above. Proposed paragraph (d) contains the index-based valuation option for valuation of your residue gas and NGLs. Under this proposed rule, you may elect to value either your residue gas or your NGLs under the index-based option, or you may elect to value both of them under this option if your residue gas or NGLs meet the requirements for using the optional valuation methodology we discuss above. Like the current Federal oil regulations (30 CFR 1206.102(d)(1)(ii)) and proposed § 1206.141(c), you cannot change your election to use this paragraph (d) to value your gas more often than once every two years. Proposed paragraph (d)(1) applies to residue gas. It has the same index price option as proposed §§ 1206.141(c)(i) through (vi) we discuss above using index pricing points. Proposed paragraph (d)(2) contains the index-based pricing option for NGLs. Under paragraph (d)(2)(i), if you sell NGLs in an area with one or more ONRR-approved commercial price bulletins available at www.onrr.gov, you may choose one bulletin, and your value for royalty purposes would be the monthly average price for that bulletin for the production month. We consider you to be selling NGLs in an area with an ONRR-approved commercial price bulletin if actual sales of NGLs that the plant processing your gas recovers are made using NGLs prices in an ONRR-approved commercial price bulletin. For example, in ONRR's experience, actual sales of NGLs recovered in plants in New Mexico commonly reference Mt. Belvieu prices in Platts, while actual sales of NGLs recovered in plants in certain parts of Wyoming reference Mt. Belvieu or Conway, Kansas prices. If your gas is processed at one of these plants with these types of actual sales arrangements, under this proposed rule, ONRR will consider you to be selling NGLs in an area with an ONRR-approved commercial price bulletin. In that case, you may elect to value your NGLs using the index price method if your NGLs meet the requirements for using that method. ONRR will monitor actual sales of NGLs and eliminate any area where an active market using NGLs prices in an ONRR-approved commercial price bulletin ceases to exist. Under proposed paragraph (d)(2)(ii), you may reduce the index-based value you calculate under paragraph (d)(2)(i) by a specified amount to account for a theoretical processing allowance and transportation and fractionation (T&F). Therefore, the reduction includes two components we calculated—an allowance based on processing allowance information lessees report to ONRR and T&F based on our review of gas plant contracts and gas plant statements. For the processing allowance component, ONRR examined processing allowances that lessees and others reported from January 2007 through October 2011. We segregated the data into 2 subsets—the first being the Gulf of Mexico (GOM) and the second being onshore Federal leases and OCS leases other than those in the GOM. We segregated the leases geographically because the GOM is closer to major market centers at Mt. Belvieu, Napoleonville, and Geismer/Sorrento and, generally, has its own processing, transportation, and fractionation regimen that is distinct from the rest of the country. We do not believe it is fair or accurate to benchmark processing for the entire country based on the economics of GOM processing. We could not segregate non-arm's-length processing allowances because lessees do not identify processing allowances as arm's-length or non-arm's-length when they report to ONRR. Rather, we calculated a weighted average cents per gallon processing allowance by month for both GOM and all other Federal leases. Using the weighted average cents per gallon processing allowance we calculated, we determined the average allowance rate over the 5-year period, along with the maximum and minimum monthly rates as follows: GOM Other Average Rate 17 ¢/gal 22 ¢/gal. Maximum Rate 29 ¢/gal 32 ¢/gal. Minimum Rate 10 ¢/gal 15 ¢/gal. Because we intend for this option to provide a simple method for ONRR to calculate and provide to lessees, we used the minimum, rather than the average rate, for the processing allowance portion of the deduction. For both the GOM and all other Federal leases, the minimum rate is 7 cents less than the average rate. ONRR believes that: (1) The minimum allowance best protects the public interest and (2) a lessee experiencing higher costs than this rate does not have to elect to use this option and the lower cost allowance. Moreover, ONRR believes that 7 cents is a reasonable tradeoff given the simplicity, certainty, and commensurate administrative savings this option would provide a lessee. For the T&F part of the reduction, ONRR examined contracts that specified T&F. If contracts did not specify T&F, we looked at the gas plant statements. If the statements listed T&F as a line item, we used that line item as the T&F. If the statements did not list T&F as a line item, we calculated the difference between the price on the plant statement and an appropriate published price to approximate the T&F. We then averaged these T&F costs for GOM, New Mexico, and other as follows: GOM New Mexico Other Average T&F 5 ¢/gal 7 ¢/gal 12 ¢/gal. We broke out New Mexico because the T&F fees for New Mexico plants were consistently around 7 cents per gallon and were considerably less than for other onshore plants. We then added the processing allowances we calculated and the T&F. Based on the 5-years' worth of data discussed above, we calculated the total NGLs reductions lessees could use under this option are as follows: GOM New Mexico Other NGLs Deduction 15 ¢/gal 22 ¢/gal 27 ¢/gal. Under paragraph (d)(2)(ii), rather than publish the reductions in the CFR, ONRR proposes to post the reductions at www.onrr.gov for the geographic location of your lease. ONRR proposes to calculate the reductions using the methodology explained above. This process would give ONRR the flexibility to quickly recalculate and provide revised reductions to lessees in response to market changes. This methodology would be binding on you and ONRR. Under paragraph (d)(4), ONRR would update the allowable reductions periodically using this methodology and post changes at www.onrr.gov . Proposed paragraph (d)(2)(iii) explains that after you select an ONRR-approved commercial price bulletin available at www.onrr.gov, you may not select a different commercial price bulletin more often than once every two years. Under proposed paragraph (d)(3), you may not take any other deductions from the value you used under this paragraph (d) because it already includes reductions for transportation and processing. Proposed paragraph (e) mirrors proposed § 1206.141(d). It explains how you must value your processed gas if you have no written contract for the sale of gas or no sale of the gas subject to this section. 1206.143 How will ONRR determine if my royalty payments are correct? In this section, ONRR proposes amendments to the current gross proceeds provisions, rewriting them in Plain Language and making them consistent with our other product valuation regulations (such as geothermal resources and Federal oil). Like those published regulations, rather than repeating the requirements or procedures in each applicable section of this proposed rule, ONRR proposes to apply this section to this entire subpart. However, the substantive requirements of proposed paragraphs (d), (e), and (f) remain unchanged. Below we discuss the paragraphs with substantive changes. Proposed paragraph (a)(1), like our current regulations, states “ONRR may monitor, review, and audit the royalties you report, and, if ONRR determines that your reported value is inconsistent with the requirements of this subpart, ONRR will direct you to use a different measure of royalty value . . . .” However, we propose to add paragraph (a)(1) that states in addition to directing you to use a different measure of value, we also may decide your value under § 1206.144 as we discuss below. Proposed paragraph (b), like our current regulations, explains “[w]hen the provisions in this subpart refer to gross proceeds, in conducting reviews and audits, ONRR will examine if your or your affiliate's 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 products.” However, we propose to add a new paragraph (b) that if ONRR determines a contract does not reflect the total consideration, ONRR may decide your value under § 1206.144 as we discuss below. Proposed paragraph (c) broadly defines three circumstances when ONRR will calculate the value of your gas using the method specified in the new proposed “default” valuation § 1206.144. During its compliance activities, ONRR encounters a wide range of situations in which lessees have inaccurately calculated value. By broadly defining the circumstances in which ONRR may calculate value, this proposed rule ensures ONRR can fulfill its statutory mandate under FOGRMA to ensure that lessees accurately calculate, report, and pay royalties (30 U.S.C. 1701 and 1711). Proposed paragraphs (c)(1) and (c)(2) contain the provisions regarding misconduct and breach of the duty to market in current 30 CFR 1206.152(b)(1)(i) and 1206.153(b)(1)(iii). Under the current regulations, if ONRR determines there is misconduct between the parties, or that the lessee has breached its duty to market, then the lessee must value its gas under the current benchmarks for non-arm's-length sales of gas in 30 CFR 1206.152(c)(2) or (c)(3) (unprocessed gas) and 1206.153(c)(2) or (c)(3) (processed gas). However, as we discuss above, ONRR proposes to eliminate the benchmarks in this rulemaking. We propose instead that if ONRR determines there is misconduct between the parties to a contract or the lessee has breached its duty to market, we may decide your value under § 1206.144 as we discuss below. As we discuss above in proposed § 1206.20, misconduct, for purposes of proposed paragraph (c)(1), means any failure to perform a duty owed to the United States under a statute, regulation, or lease, or unlawful or improper behavior regardless of the mental state of the lessee or any individual employed by, or associated with, the lessee. Misconduct, in this subpart, would be different than, and in addition to, any violations subject to civil penalties under FOGRMA, 30 U.S.C. 1719, and its implementing regulations in part 1241 of this chapter. Behavior that constitutes misconduct, under this part 1206, would not need to be willful, knowing, voluntary, or intentional. This is a valuation mechanism, not an enforcement tool. Under this proposed rule, if ONRR determines that misconduct has occurred, ONRR will calculate value under § 1206.144. However, if ONRR determines the misconduct was knowing or willful, it also could pursue civil penalties under part 1241 of this chapter. Under proposed paragraph (c)(2), ONRR defines what is a breach of the duty to market. The proposed rule specifies that ONRR may determine value under § 1206.144 if a lessee sells gas, residue gas, or gas plant products at an unreasonably low price. The proposed rule explains what ONRR could consider an “unreasonably low” price. A lessee has a duty to market gas for the mutual benefit of the United States, as lessor, and the lessee. An unreasonably low price may reflect a failure of the lessee to perform that duty. Proposed paragraph (a)(2) defines a sales price as “unreasonably low” “if it is 10 percent less than the lowest reasonable measures of market price, including, but not limited to, index prices and prices reported to ONRR for like-quality gas, residue gas, or gas plant products.” ONRR's authority to exercise this provision is discretionary; ONRR “may” decide your value if it determines your price is unreasonably low. In exercising its discretion, ONRR may consider any information that shows a price appears unreasonably low, and, thus, is not an accurate reflection of fair market value. ONRR also proposes a new paragraph (c)(3). Under proposed paragraph (c)(3), ONRR may value your gas, residue gas, or gas plant products under § 1206.144 if ONRR cannot determine if you properly valued your gas, residue gas, or gas plant products under § 1206.141 or § 1206.142 for any reason. This is a broad “catch-all” provision ONRR may use to decide the value of gas, residue gas, or gas plant products when it cannot determine if a lessee properly valued its production. ONRR will exercise this discretionary authority to meet its mandate under 30 U.S.C. 1711 to ensure accurate accounting for Federal oil and gas royalties under the different circumstances it encounters during its compliance verification activities. It is the lessee's responsibility to provide ONRR with information sufficient for us to ensure that royalties are accurately calculated. Under this provision, ONRR will still meet its statutory mandate even when a lessee fails to provide sufficient information. However, like proposed paragraph (c)(1) of this section, this is an ONRR valuation mechanism that is in addition to any civil penalty authority ONRR has under part 1241 of this chapter. We propose a new paragraph (g)(1) that requires the lessee or its affiliate to make all contracts in writing before it can use the contracts as the basis for the lessee's valuation of its gas produced from Federal leases. This proposed requirement will apply to any contract revisions or amendments. Further, ONRR proposes that all parties to the contract must sign the contracts, contract revisions, or amendments before lessees can use them as the basis for the lessee's valuation of its gas under these regulations. ONRR believes this proposed requirement is critical to the proper application of the valuation regulations. Lessees should provide to ONRR the actual, written contracts signed by all parties because those contracts document the very transactions on which the regulations require lessees to base values and allowances. Without the applicable sales, transportation, and/or processing contracts, neither the lessee nor ONRR can verify that Federal royalties are properly paid. Because ONRR would only require a lessee to provide its actual contractual arrangements that it uses to conduct its business, this requirement should place no burden on a lessee. ONRR proposes a new paragraph (g)(2) providing that ONRR may decide the value of a lessee's gas if the lessee or its affiliate fails to make all contracts, contract revisions, or amendments in writing. If the lessee cannot produce the written, signed contracts that would otherwise serve as the basis of the lessee's valuation of its gas under the regulations, ONRR may decide to determine the appropriate value of the lessee's gas under newly proposed § 1206.144 as we discuss below. Finally, ONRR proposes to add paragraph (g)(3) to make clear the new provision requiring contracts to be in writing and signed by all parties is in addition to any other recordkeeping requirements the lessee must satisfy under this title, and that this new requirement supersedes any provision in this title to the contrary. 1206.144 How will ONRR determine the value of my gas for royalty purposes? ONRR proposes a new “default” valuation § 1206.144 that ONRR may use to value your gas, residue gas, or gas plant products for royalty purposes. Because we propose the same default provision for federal oil, please refer to § 1206.105 above for more information. 1206.145 What records must I keep to support my calculations of royalty under this subpart? 1206.146 What are my responsibilities to place production into marketable condition and to market production? 1206.147 When is an ONRR audit, review, reconciliation, monitoring, or other like process considered final? 1206.148 How do I request a valuation determination or guidance? See discussion below. 1206.149 Does ONRR protect information I provide? 1206.150 How do I determine royalty quantity and quality? ONRR proposes to rewrite in Plain Language the regulations for recordkeeping, marketable condition and marketing, audit, confidentiality, and quantity and quality requirements and procedures. Also, ONRR proposes to make these sections consistent with other product valuation regulations, such as the geothermal and Federal oil regulations. In addition, rather than repeat the requirements or procedures in each applicable section of this rule, ONRR proposes to have these sections apply to this entire subpart. The substantive requirements remain unchanged. 1206.148 How do I request a valuation determination or guidance? ONRR proposes a new § 1206.148 on how to request a valuation determination or guidance. This section is the same as § 1206.108 applicable to Federal oil we discuss above, with several substantive changes. Proposed § 1206.148 replaces and expands the provisions contained in current 30 CFR 1206.152(g) and 1206.153(g). The newly proposed section provides greater clarity on the process lessees may use to request valuation guidance and determinations, as well as on the effect of ONRR's response to such requests. Adding proposed § 1206.148 will make the procedures for gas valuation requests consistent with the procedures ONRR proposes for Federal oil and Federal and Indian coal. Under proposed paragraph (a), a lessee may request a valuation determination or guidance from ONRR regarding any gas produced. Paragraph (a)(1) through (3) explains that the lessee's request must be in writing; identify all leases involved, all interest owners in the leases, and the operator(s) for those leases; and completely explain all relevant facts. In addition, under paragraphs (a)(4) through (6), a lessee must provide all relevant documents, its analysis of the issue(s), citations to all relevant precedents, including adverse precedents, and its proposed valuation method. In response to a lessee's request, under proposed paragraph (b), ONRR may (1) decide that it will issue guidance, (2) inform the lessee in writing that it will not provide a determination or guidance, or (3) request that the Assistant Secretary for Policy, Management, and Budget issue a determination. This proposal changes the current Federal oil regulations under 30 CFR 1206.107(b), which has caused confusion over whether an ONRR-issued determination is a binding appealable order or non-appealable guidance. Under this proposed rule, ONRR clarifies that we only issue non-binding guidance for valuation of Federal oil and gas and Federal and Indian coal. This proposal is consistent with ONRR's existing practice of having only the Assistant Secretary sign decisions that are binding on the Department. Also, ONRR proposes to remove the regulatory language that we will “reply to requests expeditiously.” Our practice is to reply as quickly as possible, so we do not make it a regulatory requirement. Proposed paragraphs (b)(3)(i) and (ii) identify situations in which ONRR and the Assistant Secretary typically do not provide a determination or guidance, including, but not limited to, requests for guidance on hypothetical situations and matters that are the subject of pending litigation or administrative appeals. Under proposed paragraph (c)(1), a determination the Assistant Secretary of Policy, Management and Budget signs binds both the lessee and ONRR unless the Assistant Secretary modifies or rescinds the determination. After the Assistant Secretary issues a determination, under proposed paragraph (c)(2), the lessee must make any adjustments to its royalty payments that follow from the determination. If the lessee owes additional royalties, it must pay the additional royalties due plus late payment interest calculated under §§ 1218.54 and 1218.102 of this chapter. In addition, proposed paragraph (c)(3) explains that a determination the Assistant Secretary signs is the final action of the Department and is subject to judicial review under 5 U.S.C. 701-706. Proposed paragraph (d) explains that, if ONRR issues guidance, the guidance is not binding on ONRR, delegated States, or the lessee with respect to the specific situation addressed in the guidance. This is a change from the current Federal oil regulation at 30 CFR 1206.107(d) that makes a determination ONRR issues binding on ONRR and delegated States but not the lessee. Moreover, guidance, ONRR's decision whether to issue guidance, and ONRR's decision whether to request a determination by the Assistant Secretary would not be appealable decisions or orders under 30 CFR part 1290. This is the same as current 30 CFR 1206.107(d)(1). However, as provided under current 30 CFR 1206.107(d)(2), under proposed paragraph (d)(2) of this section, if ONRR issues an order requiring the lessee to pay royalty on the same basis as the guidance, the lessee could appeal the order under 30 CFR part 1290. Under proposed paragraph (e), ONRR or the Assistant Secretary may use any of the applicable criteria in this subpart to make a determination or provide guidance. Also, under proposed paragraph (f), if a statute or regulation on which ONRR based any determination or guidance is changed, the changed statute or regulation takes precedence over the determination or guidance after the effective date of the statute or regulation, regardless of whether ONRR or the Assistant Secretary modifies or rescinds the determination or guidance. Therefore, under this proposed provision, determinations and guidance are not open-ended. 1206.151 How do I perform accounting for comparison? ONRR proposes to move the regulations in current 30 CFR 1206.155 to proposed § 1206.151, but we rewrite this section in Plain Language. This section requires a lessee to pay royalties on the greater of the value of the unprocessed gas or the value of its processed gas if the lessee, its affiliate, a person to whom the lessee transferred gas under a non-arm's-length contract, or a person to whom the lessee transferred gas without a contract processes the lessee's or its affiliate's gas and does not sell the residue gas at arm's length. However, ONRR requests comments on whether we need this proposed requirement for two reasons. First, proposed §§ 1206.142 and 1206.143 of this subpart recognize the real market value of gas today is the combined value of its constituent components—residue gas and gas plant products. And, the proposed regulations value gas sold on that basis as processed gas. There appears to be a limited market for unprocessed gas, unless it is sold based upon the constituent products contained therein, hence accounting for comparison may not be needed. Second, because the criteria that triggers dual accounting—a non-arm's-length sale of residue gas after processing—is not used to value gas under this proposed rule, dual accounting may no longer be appropriate because the residue gas is valued based on the first arm's-length sale or index-based option. ONRR also proposes to keep the requirement in current 30 CFR 1206.155 that lessees must perform dual accounting if required by lease terms. ONRR believes this provision is consistent with proposed § 1206.140(c)(4), which specifically recognizes the primacy of lease terms over the terms of the regulations when they are inconsistent. Before we discuss each section of proposed §§ 1206.152 through 1206.158 regarding transportation allowances, we believe it is helpful to discuss some general changes we make. The proposed regulations move the current regulations regarding transportation allowances from 30 CFR 1206.156 and 1206.157 to proposed §§ 1206.152 through 1206.158. The proposed gas transportation allowance regulations are changed, primarily in structure, but there also are a few substantive changes. The structure of the proposed gas transportation allowance regulations is modeled after the current Federal oil transportation allowance regulations to achieve consistency between the two. In most cases, the regulatory requirements do not change. We reorganize the current provisions and rewrite them in Plain Language. Like the current oil transportation allowance regulations, this structure provides more regulatory section headings, better organization, and greater visibility to locate regulatory requirements applicable to the lessee's particular transportation allowance situations. Also, we reorganize or combine many paragraphs that were embedded within a current section into a new section for greater visibility. We propose to segregate individual multiple requirements within paragraphs into separate paragraphs to improve visibility and identification. 1206.152 What general transportation allowance requirements apply to me? Proposed § 1206.152 retains the provisions in current § 1206.156 (“Transportation allowances—general”), makes Federal gas regulations consistent with Federal oil regulations, and consolidates provisions applicable to both arm's-length and non-arm's-length transportation in the current regulations rather than repeating those provisions in the respective sections explaining those allowances. We also rewrite the current regulations in Plain Language and only discuss substantive changes and additions below. Proposed paragraph (a) contains the same requirements as current § 1206.156(a) and includes a new provision that “[y]ou may not deduct transportation costs you incur to move a particular volume of production to reduce royalties you owe on production for which you did not incur those costs.” Consistent with current regulations, this provision prevents the lessee from claiming transportation costs incurred for a segment of transportation when the gas did not actually flow on that segment. A lessee could only claim transportation costs attributable to the actual movement of the lease production on that transportation segment. We also propose new paragraphs (a)(1) and (a)(2)(i), which are consistent with the current Federal oil rule § 1206.109(a)(2). New paragraph (a)(1) states you may take a transportation allowance when you value unprocessed gas under § 1206.141(b) or residue gas and gas plant products under § 1206.142(b) based on a sale at a point off the lease, unit, or communitized area where the gas is produced. New paragraph (a)(2)(i) states that you may take a transportation allowance when the movement to the sales point is not gathering. Neither change to the current rule is substantive because both codify existing practice and case law. Proposed new paragraph (a)(2)(ii) states that “[f]or gas produced on the OCS, the movement of gas from the wellhead to the first platform is not transportation.” It is well established that the movement of oil and gas that ONRR determines is “gathering” is not allowable as a transportation allowance. California Co. v. Udall, 296 F.2d 384 (D.C. Cir. 1961); Kerr-McGee Corp., 147 IBLA 277 (1999). However, on May 20, 1999, the then-Associate Director for the former MMS's Royalty Management Program issued “Guidance for Determining Transportation Allowances for Production from Leases in Water Depths Greater Than 200 Meters” (Deep Water Policy). The Deep Water Policy provides the following guidelines: (1) Current regulations must be followed; (2) movement costs are allocated between royalty and non-royalty bearing substances; (3) movement prior to a central accumulation point is considered gathering, movement beyond the point is considered transportation; (4) leases and units are treated similarly; (5) the movement is to a facility that is not located on a lease adjacent to the lease on which the production originates; and (6) allowances for subsea completions not located in water deeper than 200 meters are considered on a case-by-case basis. Both the current Federal oil and gas valuation rules define gathering as “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 BSEE approves for onshore and offshore leases, respectively.” 30 CFR 1206.101 (Federal oil) and 1206.151 (Federal gas). Under the Deep Water Policy, ONRR considered a subsea manifold located on the OCS in deep water to be a “central accumulation point” regardless of whether it was actually a central accumulation or treatment point as ONRR's regulations require. Since ONRR issued the Deep Water Policy, lessees have been deducting the costs of moving bulk production from the subsea manifold to the platform where the oil and gas first surface. In addition, lessees have attempted to expand the Deep Water Policy to deem subsea wellheads “central accumulation points” and take transportation allowances from the sea bed floor to the first platform where the bulk production surfaces. Thus, lessees have taken transportation allowances under the Deep Water Policy, in some instances, for movement ONRR considers non-deductible “gathering” under its regulations. In addition, the Interior Board of Land Appeals (IBLA) has concluded there are three definitive attributes of gas gathering lines: (1) They move lease production to a central accumulation point; (2) they connect to gas wells; and (3) they bring gas by separate and individual lines to a central point where it is delivered into a single line. Kerr-McGee Corp., 147 IBLA at 282 (citations omitted). In Kerr-McGee, the IBLA stated that “even though production is moved across lease boundaries, because it is treated and sold on adjacent leases the costs of moving it there are properly regarded as gathering, not transportation.” Id. at 283 (citations omitted). Under Kerr-McGee, almost all of the movement the Deep Water Policy allows as a transportation allowance is, in actuality, non-deductible “gathering” under ONRR's current valuation regulations. We have determined that the Deep Water Policy is inconsistent with our regulatory definition of gathering and Departmental decisions interpreting that term. Therefore, we propose to rescind the Deep Water Policy in this rulemaking. We propose to accomplish this by making two changes. First, consistent with Kerr-McGee, we propose to add to the definition of “gathering” that any movement of bulk production from the wellhead to a platform offshore is gathering, not allowable transportation. Second, we propose to add a new paragraph (a)(2)(ii) to this section that states “[f]or gas produced on the OCS, the movement of gas from the wellhead to the first platform is not transportation.” We also make this change to proposed Federal oil § 1206.110(a)(2)(ii). Proposed paragraph (b) of this section contains and consolidates current requirements in 30 CFR 1206.156(b) and 1206.157(a)(2) and (b)(3) regarding allocation of transportations costs based on your or your affiliate's cost of transporting each product if you transport one or more products in the gaseous phase in a transportation system. Proposed paragraph (c)(1) contains and consolidates current requirements in 30 CFR 1206.157(a)(2) and (b)(4) which all apply to allocation of transportations costs when you or your affiliate transport both gaseous and liquid products in the same transportation system. Under proposed paragraph (d), if you value unprocessed gas under § 1206.141(c) or residue gas and gas plant products under § 1206.142(d)—the index-based valuation options—you may not take a transportation allowance. This is because the index-based valuation provisions already incorporate the costs of transportation. Proposed paragraph (e)(1), eliminates the current provision allowing lessees to request transportation allowances in excess of 50 percent of the sales value of the unprocessed gas, residue gas, or NGLs. Currently, ONRR limits transportation allowances and factors to 50 percent of the sales value of unprocessed gas, residue gas, or gas plant products unless we approve an exception to the limitation. To ensure a fair return to the public and to limit ONRR's administrative costs to process such requests, the proposed regulation eliminates the exception to the 50-percent limit. ONRR believes the current 50-percent limit on transportation-related costs is adequate in the vast majority of transportation situations. Thus, paragraph (e)(2) provides that any existing approvals for the exception to the limitation terminate on the effective date of the final rule. We will not grandfather any existing approval to exceed the 50-percent limit. Proposed paragraph (f) continues the current requirement under 30 CFR 1206.157(a)(4), applicable to arm's-length transportation, that lessees must express transportation allowances for residue gas, gas plant products, or unprocessed gas in a dollar-value equivalent. We propose to also apply this requirement to non-arm's-length transportation consistent with existing practice. We further propose that if your or your affiliate's payments for transportation under a contract are not in dollars-per-unit, you must convert the consideration you or your affiliate paid to its dollar-value equivalent. Like the default provision for valuation we discuss above under § 1206.143(c), proposed paragraphs (g)(1), (2), and (3) provide that ONRR may determine your transportation allowance under § 1206.144, if: (1) There is misconduct by or between the contracting parties; (2) the total consideration the lessee or its affiliate pays under an arm's-length contract does not reflect the reasonable cost of transportation because the lessee breached its duty to market the unprocessed gas, residue gas, or gas plant products for the mutual benefit of the lessee and the lessor by transporting such products at a cost that is unreasonably high; or (3) ONRR cannot determine if the lessee properly calculated a transportation allowance under § 1206.153 or § 1206.154, for any reason. Under proposed paragraph (g)(2), ONRR may consider an allowance to be unreasonably high if it is 10-percent higher than the highest reasonable measures of transportation costs, including, but not limited to, transportation allowances lessees and others report to ONRR and tariffs for gas, residue gas, or gas plant products transported through the same system. Finally, we propose a new provision under paragraph (h) to make clear that you do not need ONRR's approval before reporting a transportation allowance for costs that you incur. This provision is in the current regulations that apply to arm's-length transportation at 30 CFR 1206.157(a), but we propose to apply it to non-arm's-length transportation as well. This is consistent with existing practice. 1206.153 How do I determine a transportation allowance if I have an arm's-length transportation contract? Proposed § 1206.153 explains how lessees must determine a transportation allowance under arm's-length transportation contracts. As we discuss above, we propose to restructure this section for consistency with the Federal oil transportation allowance regulations. In addition, we move the requirements for non-arm's-length transportation allowances to a separate § 1206.154. Proposed paragraph (a)(1) states that this section applies to both the lessee and its affiliate if the lessee chooses to use the affiliate's arm's-length sales contract for valuation and if that affiliate incurs transportation costs under an arm's-length transportation contract to move the lease production to the sales point. However, ONRR will determine your transportation allowance under § 1206.152(g) if ONRR determines there is misconduct, the arm's-length transportation cost is unreasonably high, or ONRR cannot determine if your transportation allowance is proper. This provision gives ONRR greater discretion and flexibility to determine transportation allowances (for example, when arm's-length transportation service providers charge bundled fees). See the discussion of bundled fees in proposed § 1206.141 above. ONRR proposes to eliminate the provision in current 30 CFR 1206.157(a)(5) that allows lessees to report transportation costs, in certain circumstances, as a transportation factor. Rather, we propose that a lessee must report separately all transportation costs under both arm's-length and non-arm's-length sales contracts as a transportation allowance on Form ONRR-2014. ONRR believes that requiring lessees to report all deductions for transportation costs separately as allowances on Form ONRR-2014 is more transparent, supports ONRR's increased data mining efforts to promote accuracy, and assists State and Federal auditors with their compliance work. We propose this same change for oil produced from Federal lands. Proposed paragraph (b) allows a lessee to include the same costs we allow under current 30 CFR 1206.157(f) in its transportation allowance. Under new paragraph (b)(11), we also propose that a lessee may include in its transportation allowance hurricane surcharges the lessee or its affiliate pay. This proposal is consistent with existing practice. Under proposed paragraph (c), we specify transportation costs we would not allow a lessee to include in its transportation allowance. These non-allowable costs remain mostly the same as those we currently disallow under 30 CFR 1206.157(g). We believe it is already clear the cost of boosting gas ( e.g. recompressing residue gas at the plant after processing) is not a deductible cost of transportation under current 30 CFR 1202.151(b) and the Assistant Secretary's decision at issue in Devon. Nevertheless, proposed paragraph (c)(8) specifically states that the costs of boosting residue gas are not allowable as a cost of transportation. Finally, we propose a new paragraph (d) that applies if you have no written contract for the arm's-length transportation of gas. In that case, ONRR determines your transportation allowance under proposed § 1206.144. Under this proposal, you have to propose to ONRR a method to determine the allowance using the procedures in § 1206.148(a) and could use that method until ONRR issues its determination. This paragraph only applies when there is no contract for arm's-length transportation. Thus, it would not apply if lessees perform their own transportation. Rather, § 1206.154 regarding non-arm's-length transportation allowances applies. 1206.154 How do I determine a transportation allowance if I have a non-arm's-length transportation contract? We propose § 1206.154 as a separate section explaining how to calculate transportation allowances under a non-arm's-length contract, such as where the lessee ships its production through its own pipeline or through a pipeline its affiliate owns. Under proposed paragraph (a), ONRR continues the provision in current 30 CFR 1206.157(b) that does not recognize contracts between the lessee and its affiliate or any other person without opposing economic interests regarding that contract. Like the current regulations, you will determine non-arm's-length transportation allowances based on your actual costs or the actual costs of the affiliated pipeline owner. Proposed paragraph (b) generally explains costs you may include in your transportation allowance. Paragraph (b)(1) explains the lessee's or its affiliate's actual costs include capital costs and operating and maintenance expenses under paragraphs (e), (f), and (g) of this section. Proposed paragraph (b)(2) explains you also could include overhead under paragraph (h) of this section. Under proposed paragraph (b)(3), we revise the current regulation to clarify the methodology for the two options to calculate depreciation. Under this proposed rulemaking, we allow lessees to choose between depreciation and a return on undepreciated capital investment under paragraph (i)(1) of this section, or a cost equal to a return on the initial depreciable capital investment in the transportation system under paragraph (i)(2) of this section. Finally, paragraph (b)(4) allows the lessee to continue to claim a rate of return on the reasonable salvage value of the transportation system after it is fully depreciated. For example, if the pipeline had a salvage value of 5 percent, the lessee may claim a rate of return on 5 percent of the system value, even though we would allow no further depreciation. See the discussion of reasonable salvage value in proposed § 1206.112(i)(1)(iii). We also propose to remove the provisions of current § 1206.175(b)(5) that allow a lessee with a non-arm's-length contract to use FERC or State-regulatory-agency approved tariffs as an exception from the requirement to calculate actual costs. We remove this provision to make it consistent with the current Federal oil valuation regulations. Under the proposed rule, lessees must compute their actual costs to determine transportation allowances under non-arm's-length contracts even when a regulatory agency has approved a tariff. Proposed paragraph (c) further explains the transportation costs you may and may not include in a transportation allowance. Proposed paragraph (c)(1) states that, to the extent that you have not already included in your transportation allowances the allowable costs under paragraphs (e) through (g) of this section, you may include in your allowance the actual transportation costs we list under § 1206.153(b)(2), (5), and (6) of this subpart (Gas supply realignment (GSR) costs, Gas Research Institute (GRI) fees, and Annual Charge Adjustment (ACA) fees that FERC imposes). ONRR proposes to disallow the remaining costs we allow a lessee to include in arm's-length transportation allowances under § 1206.153(b) because the lessee would not or should not ordinarily incur the costs as a pipeline owner or be charged for those costs by its affiliate. However, there may be instances when specific costs integral to transportation could be included in the pipeline owner's operating and maintenance costs. ONRR invites comments on what types of costs, other than those identified in § 1206.153(b)(2), (5), and (6), may be actual costs of transportation under non-arm's-length transportation arrangements. ONRR also proposes to eliminate the current provision allowing lessees to deduct the costs of pipeline losses, both actual and theoretical, under non-arm's-length transportation situations. These regulations prohibited actual or theoretical pipeline losses prior to the 1997 gas transportation allowance revisions that incorporated new costs resulting from FERC Order No. 636. The advent of Order No. 636 should not have had any bearing on such non-arm's-length costs. Therefore, ONRR proposes to remove this provision. ONRR recognizes that pipeline losses are distinct from transportation fuel that is used on a pipeline to power compressors used for actual transportation. Under the proposal, ONRR continues to permit lessees to claim an allowance for actual fuel used for qualifying transportation purposes. In addition, we continue to disallow fuel for non-approved off-lease compressors and off-lease fuel for other processes necessary to place lease production in marketable condition. Proposed paragraph (c)(2) explains that we do not allow a lessee to include in its non-arm's-length transportation allowances the same costs we do not allow to be included in arm's-length transportation allowances under proposed § 1206.153(c). Like the arm's-length provision, proposed paragraph (d) states that for non-arm's-length transportation allowances, the lessee may not duplicate allowable transportation costs when it calculates an allowance. For example, if the lessee includes GRI costs in its operating costs under paragraph (b), it may not also include those costs under paragraph (c). Proposed paragraphs (e) through (h) contain the same requirements as current 30 CFR 1206.157(b)(2)(i), (ii), and (iii), but we rewrite the provisions in Plain Language and make them consistent with the current Federal oil regulations. Proposed paragraph (i) retains the requirements of current 30 CFR 1206.157(b)(2)(iv) regarding depreciation, but we rewrite those provisions in Plain Language and make them consistent with the Federal oil regulations. ONRR proposes to eliminate the reference to transportation facilities first placed in service after March 1, 1988. When ONRR published its Federal gas valuation regulations on January 15, 1988, it changed the requirements necessary to receive transportation and processing allowances. In recognition that certain transportation and processing facilities had been given approval prior to those regulations' effective date (March 15, 1988), ONRR made the new requirements apply only to facilities that were placed in service on or after the effective date of those regulations. Now more than twenty years later, ONRR believes that none of the facilities placed in service before March 15, 1988, are still eligible for depreciation under the requirements in effect prior to March 15, 1988. Therefore, we propose to remove this outdated language from the proposed regulations. Under paragraph (i)(3), ONRR proposes to revise the rate of return from 1.3 times the Standard & Poor's BBB bond rate in current 30 CFR 1206.157(b)(2)(v) to the rate without a multiplier, in other words 1 times the BBB bond rate. We make the same change to Federal oil, so please refer to our discussion of proposed § 1206.112(i)(3). 1206.155 What are my reporting requirements under an arm's-length transportation contract? This section would contain essentially the same provisions as current 30 CFR 1206.157(c)(1). However, ONRR proposes to add the term “affiliate” to paragraph (b). Under the new proposed valuation provisions, which use an affiliate's arm's-length sales contract, ONRR allows a transportation allowance to the arm's-length sales point and, therefore, needs the associated transportation contracts. In addition, ONRR proposes to eliminate the reference to allowances in effect prior to March 1, 1988, under current 30 CFR 1206.157(c)(1)(iii). As stated above, ONRR believes that none of facilities predating the 1988 rule change are still eligible for depreciation under the requirements in effect prior to March 15, 1988. Therefore, we are removing this language from the proposed regulations. 1206.156 What are my reporting requirements under a non-arm's-length transportation contract? This section contains essentially the same provisions as current 30 CFR 1206.157(c)(2). In this proposed rule, ONRR eliminates the reference in current 30 CFR 1206.157(c)(2)(v) to allowances in effect prior to March 1, 1988. 1206.157 What interest or penalties apply if I improperly report a transportation allowance? Under proposed § 1206.157, ONRR consolidates the penalty and interest provisions for improper allowances. Currently, such provisions are contained under both the general transportation and determination of transportation allowances sections of the regulations. Proposed paragraph (a)(1) slightly modifies current 30 CFR 1206.156(d) by using the term “unauthorized” in the context of “If ONRR determines that you took an unauthorized transportation allowance, then you must pay any additional royalties due. . . .” However, this change would not alter the meaning of the current provisions. Examples of unauthorized transportation allowances include, but are not limited to, exceeding the 50-percent limitation, including costs necessary to place the gas into marketable condition, or including other costs that are not integral to the transportation of lease production. Proposed paragraph (a)(2) states that a lessee may be entitled to a credit with interest if it understated its transportation allowance. This provision amends current 30 CFR 1206.157(e) to comply with RSFA's provision that entitles lessees to interest on overpayments (30 U.S.C. 1721(h)). Proposed paragraph (b) states that, if the lessee deducts a transportation allowance that exceeds 50 percent of the value of the gas, residue gas, or gas plant products transported, the lessee must pay late payment interest on the excess allowance amount taken from the date that amount is taken until the date it paid the additional royalties due. This changes the current requirement that interest is calculated from the date the allowance is taken until the lessee files a request for an exception. This change results from ONRR proposing to eliminate allowance exceptions. Proposed paragraph (c) restates current 30 CFR 1206.156(d). 1206.158 What reporting adjustments must I make for transportation allowances? Section 1206.158 restates the requirements of current 30 CFR 1206.157(e), except we rewrite the provisions in Plain Language. 1206.159 What general processing allowances requirements apply to me? Like the amendments to transportation allowances discussed above, ONRR proposes to rewrite the current processing allowance regulations at 30 CFR 1206.158 in Plain Language, make them cons [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2014-30033. Public record. Not legal advice.