Repeal of Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform, 36934-36989 [2017-16571]

Download as PDF 36934 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations DEPARTMENT OF THE INTERIOR Office of Natural Resources Revenue 30 CFR Parts 1202 and 1206 [Docket No. ONRR–2017–0001; DS63644000 DR2000000.CH7000 178D0102R2] RIN 1012–AA20 Repeal of Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform Office of Natural Resources Revenue, Interior. ACTION: Final rule. AGENCY: The Office of Natural Resources Revenue (ONRR) is repealing the Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform Final Rule, published July 1, 2016, and effective January 1, 2017. Simultaneously, ONRR is reinstating the valuation regulations governing the valuation of Federal oil, Federal gas, and Federal and Indian coal that were in effect before January 1, 2017. DATES: This rule is effective on September 6, 2017. FOR FURTHER INFORMATION CONTACT: For questions on technical issues, contact Elizabeth Dawson at (303) 231–3653, Amy Lunt at (303) 231–3746, Peter Christnacht at (303) 231–3651, or Karl Wunderlich at (303) 231–3663. SUPPLEMENTARY INFORMATION: SUMMARY: I. Background mstockstill on DSK30JT082PROD with RULES3 A. General This final rule repeals in its entirety the Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation Reform Final Rule (2017 Valuation Rule) that ONRR published in the Federal Register on July 1, 2016 (81 FR 43338), and that was effective on January 1, 2017. The 2017 Valuation Rule made changes to existing regulations governing royalty valuation and reporting practices for oil, gas, and coal. As stated in the 2017 Valuation Rule’s preamble, the purpose of implementing the rule was (1) to offer greater simplicity, certainty, clarity, and consistency in product valuation for mineral lessees and mineral revenue recipients; (2) to ensure that Indian mineral lessors receive the maximum revenue from coal resources on their land, consistent with the Secretary’s trust responsibility and lease terms; (3) to decrease industry’s cost of compliance and ONRR’s cost to ensure industry compliance; and (4) to provide early certainty to industry and to ONRR that companies have paid every dollar due. 81 FR 43338. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 After the 2017 Valuation Rule was published, however, ONRR discovered several significant defects in the rule that would have undermined its purpose and intent. In addition, during the same time period (July 1, 2016, to the present) we received numerous comments from the regulated community and other members of the public, both in response to the proposed rule of repeal that we published in the Federal Register on April 4, 2017, and in other public forums, that were highly critical of certain provisions in the rule. In light of the defects that we discovered in the rule and after carefully considering all of the comments we received, we have decided to repeal the 2017 Valuation Rule in its entirety, principally for the following three reasons: First, the 2017 Valuation Rule has a number of defects that make certain provisions challenging to comply with, implement, or enforce. Absent their repeal, the rule would compromise ONRR’s mission to collect and account for mineral royalty revenues; could affect royalty distributions to ONRR’s State and Tribal partners; and would impose a costly and unnecessary burden on Federal and Indian lessees. Second, On March 28, 2017, the President issued E.O. 13783—Promoting Energy Independence and Economic Growth, 82 FR 16093. The executive order directs Federal agencies to review all existing regulations and other agency actions and, ultimately, to suspend, revise, or rescind any such regulations or actions that unnecessarily burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. Based on our own internal review, as well as on the comments we received both before and during the process of promulgating this rule of repeal, we have concluded that certain provisions of the 2017 Valuation Rule would unnecessarily burden the development of Federal oil and gas and Federal and Indian coal beyond the degree necessary to protect the public interest or otherwise comply with the law. Third, on March 29, 2017, the Secretary of the Interior (Secretary) announced that he will reestablish the Royalty Policy Committee (RPC) under the Federal Advisory Committee Act. The RPC will advise ONRR on current and emerging issues related to the determination of fair market value and the collection of royalties from energy and natural resources on Federal and Indian lands. The RPC will be composed of Federal representatives and stakeholders from energy and PO 00000 Frm 00002 Fmt 4701 Sfmt 4700 mineral interests, academia, public interest groups, States, Indian Tribes, and individual Indian mineral interest owners. The RPC will provide a forum for engaging with key stakeholders and the public on many of the same issues we attempted to address in the 2017 Valuation Rule. ONRR expects that further internal assessment and analysis combined with consultations facilitated by the RPC’s reestablishment will lead to the development and promulgation of a new, revised valuation rule that will address the various problems that have now been identified in the rule we are repealing. At the same time that we are repealing the 2017 Valuation Rule, we are reinstating the regulations governing the valuation of oil, natural gas, and coal produced from Federal leases and coal produced from Indian leases that were in effect before January 1, 2017. These regulations will apply prospectively to oil, gas, and coal produced on or after the effective date that we have specified in the DATES section of this preamble. We intend to apply and construe the prior regulations in a manner consistent with the preambles published in conjunction with the original rulemakings and in accordance with administrative and judicial decisions interpreting these regulations. Finally, upon taking effect, this repeal of the 2017 Valuation Rule will supersede the notification of the postponement of the effectiveness of the rule that we published in the Federal Register on February 27, 2017. 82 FR 11823. When this repeal takes effect, the so-called administrative stay of the rule will be lifted. B. Secretary’s Authority To Promulgate Regulations or Reinstate Prior Regulations Under FOGRMA Section 301 of the Federal Oil and Gas Royalty Management Act (FOGRMA), as amended, codified at 30 U.S.C. 1751, grants the Secretary broad authority to prescribe such rules and regulations, issued in conformity with the Administrative Procedure Act (APA), as he deems reasonably necessary to create a thorough system for collecting and accounting for Federal and Indian mineral royalties. FOGRMA creates the legal framework for the collection and accounting system, but FOGRMA also grants the Secretary, acting through ONRR, broad discretion as to how to build it out. Put another way (as courts sometimes have), FOGRMA grants the Secretary, acting through ONRR, broad discretion to regulate interstitially to interpret and implement the statute. There is not a single right way for ONRR to exercise its congressionally E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations mstockstill on DSK30JT082PROD with RULES3 delegated authority to interpret and implement FOGRMA; on the contrary, there are many ways in which ONRR may legitimately accomplish its task, as long as the way it chooses is consistent with the statutory language and the congressionally prescribed legal framework. ONRR believes that the prior regulations, which will be reinstated by this final rule, are fully consistent with FOGRMA and other applicable federal statutes and are an effective and efficient means of valuing Federal and Indian minerals, as evidenced by their long and successful use before the promulgation of the 2017 Valuation Rule. C. Chronology of Events Following Promulgation of 2017 Valuation Rule On July 1, 2016, ONRR published the final 2017 Valuation Rule in the Federal Register. Although the rule took effect on January 1, 2017, first reports and royalty payments under it were not due until February 28, 2017. To facilitate the transition to the new regulations, ONRR conducted eleven training sessions for industry reporters in different locations between October 17, 2016, and December 15, 2016. We designed the training sessions to educate affected parties on how to value production and report and pay royalties under the 2017 Valuation Rule. The trainings also provided a forum in which lessees could ask us questions about the rule and how ONRR would implement and enforce it. At the same time that ONRR was conducting the trainings and reviewing comments and questions about the rule, ONRR was also receiving numerous written requests for guidance that asked many of the same questions that were being raised at the live sessions. The feedback we received through the training sessions and guidance requests revealed certain unforeseen defects in, or unintended consequences of, portions of the 2017 Valuation Rule. Lessees raised multiple questions that ONRR had not previously considered and was not prepared or able to answer, particularly with respect to the coal valuation provisions. For example, lessees argued that valuing coal based on the first arm’s-length sale of coal as electricity is a difficult task because the sale price of electricity does not reflect the value of coal in a simple, predictable fashion—electricity markets are too diverse and complex to trace electricity prices back to the lease. Lessees also asked questions about how to value coal production in certain non-arm’s-length transactions under the new definition of ‘‘coal cooperative.’’ And lessees asked ONRR specific questions that we had VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 not previously considered about how, and under what circumstances, we would implement the default provision with respect to oil, gas, and coal. At bottom, by the middle of December 2016 we had become aware that the rule contained several defects that, at a minimum, would seriously complicate, and probably compromise, ONRR’s ability to implement and enforce certain provisions. On December 29, 2016, three different sets of petitioners, some of whom had previously requested guidance from ONRR, filed three separate petitions challenging the 2017 Valuation Rule in the United States District Court for the District of Wyoming. The petitioners alleged that the rule created widespread uncertainty about reporting and payment of royalties, and in some respects, was unreasonably difficult to comply with. The petitioners’ arguments echoed the questions and concerns that had been raised at the reporter training sessions and in various guidance requests. By late January 2017 we recognized that implementing the 2017 Valuation Rule would be contrary to the rule’s stated purpose of offering greater simplicity, certainty, clarity, and consistency in product valuation. We also recognized that the defects in the rule were significant enough that implementation could undermine and compromise ONRR’s mission to collect, account for, and verify mineral royalties for the United States and its State and Tribal partners. With the February 28, 2017, reporting deadline approaching and while we were actively considering internally what to do about the previously identified defects in the 2017 Valuation Rule, the petitioners in the litigation sent ONRR a letter (dated February 17, 2017) requesting that ONRR postpone the rule’s effective date. Prompted by that request, but based on ONRR’s own independent assessment of the defects in the rule and the harm that could result by requiring lessees to comply with it, we decided that it was in the best interest of the regulated community, the royalty beneficiaries, and the public in general to preserve the regulatory status quo while the litigation was pending. Accordingly, on February 27, 2017, we published in the Federal Register a notification postponing the effectiveness of the rule pursuant to 5 U.S.C. 705 of the APA, pending judicial review. 82 FR 11823. Meanwhile, the nation had elected a new President in November 2016, and the new administration had taken office on January 20, 2017. On March 28, 2017, the President issued E.O. 13783— PO 00000 Frm 00003 Fmt 4701 Sfmt 4700 36935 Promoting Energy Independence and Economic Growth, 82 FR 16093, which directed the heads of executive agencies to review all existing regulations, orders, guidance documents, policies, and other similar agency actions that potentially burden the development or use of domestically produced energy resources and, ultimately, to suspend, revise, or rescind those agency actions that do so unnecessarily. The executive order provided additional impetus to our ongoing review of the 2017 Valuation Rule, and we discovered some additional substantive problems with the rule. As a result of all of those developments, on April 4, 2017, we published in the Federal Register a notice proposing to repeal the 2017 Valuation Rule in its entirety and soliciting public comment on the proposal. 82 FR 16323. At the same time, we recognized that certain provisions in the 2017 Valuation Rule had been, and continued to be, well received. Therefore, concurrent with the proposed repeal, we also published an Advance Notice of Proposed Rulemaking soliciting public comment on two scenarios: (1) If the 2017 Valuation Rule were repealed, whether a new valuation rule is needed and, if so, what particular issues the new valuation rule should address; and (2) if the 2017 Valuation Rule were not repealed, what changes should be made to the rule (82 FR 16325, April 4, 2017). The comment period for the proposed repeal rule closed on May 4, 2017. We received more than a thousand comments from 2,342 commenters both for and against repeal. We carefully considered all of the comments we received and, for the reasons discussed further below, have decided at this time to repeal the 2017 Valuation Rule in its entirety. ONRR will continue to assess the substantive issues addressed in the 2017 Valuation Rule and expects to in the near future promulgate a new, revised valuation rule that will address the various problems that have been identified in the rule we are repealing. D. Substantive Defects in, and Administrative Challenges Posed by, the 2017 Valuation Rule 1. Valuing Coal Using the Sale Price of Electricity The 2017 Valuation Rule required lessees to value certain non-arm’s-length sales of Federal and Indian coal based on the first arm’s-length sale of electricity. For several reasons we have concluded that this provision of the rule is unnecessarily complicated and burdensome to implement or enforce. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36936 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations ONRR has long valued oil, gas, and coal based on the first arm’s-length sale of the resource because we believe that such sales are the best indicator of market value. In promulgating the 2017 Valuation Rule, ONRR incorrectly assumed that it would be reasonable for lessees to ‘‘net back’’ to the value of coal from arm’s-length electrical sales, the same way that lessees ‘‘net back’’ to value from the first arm’s-length sale by an affiliate. We also incorrectly assumed that using such sales would accurately reflect the value of coal because the majority of coal mined from Federal and Indian lands is used to generate electricity. But we failed to fully consider other factors that determine what a generating company charges for its electricity. The price of electricity also reflects the company’s costs to construct, operate, and maintain its depreciable capital assets; its costs to operate and maintain other necessary infrastructure; its costs to comply with applicable Federal and State laws; and its corporate overhead and other internal corporate costs. All of those factors may (and do) vary from company to company and from state to state. Unlike an arm’s-length sale of coal, where the sale price directly and accurately reflects the value of the coal, the sale price of electricity is determined by many factors in addition to the price of coal. Moreover, electricity is generated, transmitted, and distributed through regional grids where the electricity is maintained for delivery at specified voltages and frequencies. The regional grids function as pools that are fed by electricity generated from a variety of different resources, including natural gas, solar, wind, geothermal, and coal. The electricity is then sold in wholesale markets in a variety of ways, including, but not limited to, firm and non-firm sales, long-term and short-term sales, interruptible sales, and daily spotmarket sales. The markets also include ancillary services, such as spinning and non-spinning reserves, voltage and frequency control, and load following. Each of these sales commands a different price. We have concluded at this time that the approach taken in the 2017 Valuation Rule establishes an unreasonable requirement for the lessee or ONRR to dissect these services and sales, and trace those sales back to coal produced from the lease, particularly because electricity generated from coal is pooled with electricity generated from other resources before it is sold. In short, it would be very challenging for lessees to calculate and pay royalties based on the sale price of electricity and VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 similarly challenging for ONRR to verify the accuracy of those calculations. Finally, the 2017 Valuation Rule failed to address the increasingly common situation in which gross proceeds accrue to a lessee’s affiliate. The rule stated that lessees value their Federal and Indian coal production on ‘‘the gross proceeds accruing to you for the power plant’s arm’s-length sales of the electricity less applicable transportation and washing deductions.’’ (Emphasis added.) As used in that regulation, the word ‘‘you’’ referred to the lessee, which the rule defined as ‘‘any person to whom the United States, an Indian Tribe, and/or individual mineral owner issues a lease, and any person who has been assigned all or part of record title, operating rights, or an obligation to make royalty or other payments by the lease.’’ For Federal and Indian coal, the definition of lessee included ‘‘an operator, payor, or other person with no lease interest who makes royalty payments on the lessee’s behalf.’’ The rule was silent, however, on how to value coal when the gross proceeds accrued to a lessee’s affiliate. This oversight would have undermined ONRR’s mission and responsibility to collect and verify royalties, which would have had a direct impact on revenue accruing to ONRR’s State and Tribal partners. 2. Definition of ‘‘Coal Cooperative’’ The 2017 Valuation Rule defined ‘‘coal cooperatives’’ to capture the arm’s-length value of coal in those limited circumstances in which unaffiliated companies cooperate to market and exchange coal for mutual economic advantage. But the term was defective in several respects. At bottom, the definition was overly broad and ambiguous and created too much confusion to be effective or enforceable. And because the definition was too broad, it asked lessees to perform an unreasonably difficult task, that is, to value coal based on the sale price received by a third-party company that was neither affiliated, nor in a contractual relationship, with the lessee. More specifically, the 2017 Valuation Rule did not define what entities are included in a coal cooperative, nor did the rule adequately identify what type of behavior, conduct, or economic relationships constitute a coal cooperative. Thus, the rule did not provide lessees with meaningful direction to enable them to determine whether they are part of a coal cooperative and, if so, what other entities may also be part of that cooperative. Indeed, the definition was so broad that it would have captured PO 00000 Frm 00004 Fmt 4701 Sfmt 4700 almost any entity engaged in the production, marketing, and transportation of coal, regardless of how far removed that entity was from the lessee. Consequently, it would have been unreasonable for either ONRR or the lessee to determine where the coal cooperative began and where it ended. By extension, it would have been unreasonable for either ONRR or the lessee to determine when the first arm’slength sale occurred. As a result, lessees could not have valued their coal, and ONRR (or States or Tribes, acting under authority by ONRR) could not have verified that value. That inadvertent and unfortunate confusion was, of course, directly contrary to ONRR’s intent when it promulgated the rule. What is more, the definition would have required lessees to perform an unreasonably difficult task. For example, a federal lessee in a coal cooperative could sell its coal to an unaffiliated third party that is also in the cooperative. But because the parties are part of the same cooperative, we would not have considered that sale to be an arm’s-length transaction. The third party then could have transferred the coal to an affiliate, who could have sold the coal at arm’s-length. Under those circumstances, the rule would have required the lessee to value its coal based on the sales price received by the third-party’s affiliate, a company that was neither affiliated, nor in a contractual relationship, with the lessee. Under this scenario, the lessee probably could not have obtained the sales price information it needed to determine the royalty-bearing value of its coal. Last, the definition of coal cooperative was unnecessary because it attempted to solve a problem that was already addressed by the prior (and soon-to-bereinstated) regulations. In the example, under the prior regulations ONRR would still obtain fair market value for the coal because the lessee and third party lack opposing economic interests, and we therefore would apply the provision in the regulations for valuing coal in non-arm’s-length transactions. Under that provision, depending on the circumstances, ONRR could still value the coal based on the first arm’s-length transaction under the fourth benchmark in 30 CFR 1206.257(c)(2) (Federal coal) or 1206.456(c)(2) (Indian coal). 3. Default Provision Statutes and lease terms grant the Secretary considerable authority and discretion to establish the reasonable value of Federal and Indian minerals. By promulgating the so-called default provision, ONRR was attempting to offer greater clarity, consistency, and E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations predictability by defining when, where, and how the Secretary would exercise his discretionary authority to use an alternative methodology to value minerals. We attempted to explain that we would invoke the default provision only in specific and limited situations when we could not determine whether a lessee had properly paid royalties under the regulations. Those situations include when a lessee fails to provide documents during an audit, when a lessee engages in misconduct, when a lessee breaches its duty to market, or any other situation that compromises our ability to reasonably determine the fair market value of the oil, gas, or coal. But because we described those circumstances so broadly, without limits or meaningful guidance, the rule created more confusion and uncertainty than it resolved. We also failed to appreciate the numerous administrative challenges posed by the default provision. For example, the 2017 Valuation Rule did not identify who within ONRR has the authority to invoke the default provision or whether that decision must be approved or may be appealed. The rule defined ‘‘misconduct’’ so broadly that lessees, ONRR, and ONRR’s State and Tribal partners were left without any meaningful guidance on what type of misconduct triggered the default provision. At the same time, the rule was silent on whether ONRR must make a formal finding of misconduct before the default provision is invoked, who has the authority make such a finding, and whether such a finding is subject to review. We believe that those ambiguities would have led to very inconsistent applications of the rule. The 2017 Valuation Rule also did not address whether the default provision was a tool of last resort or a vehicle to collect and verify royalties more efficiently. For example, the rule offered no guidance on what would happen if ONRR invoked the default provision to value production because the lessee failed to provide documents necessary to value the production, and the lessee later produces those documents. Nor did the rule fully explain how the default provision interacted with ONRR’s civil penalty regulations. For example, if a lessee knowingly or willfully fails to provide documents during an audit, the rule was silent on Federal gas 1206.141(e) 1206.142(f) 1206.153(d) 1206.160(b)(2) VerDate Sep<11>2014 whether ONRR would issue a civil penalty for failing to permit an audit, or whether ONRR would complete the audit by valuing the production under the default provision, or both. These challenges, and many others, made the default provision confusing to lessees and would have made it difficult, for ONRR to implement and enforce. Finally, with or without the default provision, ONRR already has the authority to establish the value of Federal and Indian minerals when we cannot determine whether a lessee properly paid royalties. While the default provision was a well-intended attempt to provide certainty and predictability by clarifying and codifying that authority, we now recognize that the default provision created more confusion, uncertainty, and apprehension than it resolved. 4. Requirement That Arm’s-Length Contracts Be in Writing and Signed by All Parties The 2017 Valuation Rule required both lessees and their affiliates to reduce all contracts, contract revisions, or amendments to writing and have them signed by all of the parties. The rule further stated that where the lessee did not have in place a written contract signed by all of the parties, ONRR could use the default provision to value the oil, gas, or coal at issue. Based on the comments we received, we have reconsidered our position on this requirement. We now agree with the majority of commenters that this provision of the rule is unnecessary, overly burdensome, and potentially defective. First, this provision overlooked the fact that unwritten agreements or unsigned, written agreements may be binding, legally enforceable contracts. Second, this provision contradicted the definition of ‘‘contract’’ in the rule itself, which defined ‘‘contract’’ as ‘‘any oral or written agreement . . . that is enforceable by law’’ and which did not require the contract to be signed by the parties. Third, the preamble stated that ONRR could discount or ignore an arm’s-length contact if the contract were not in writing and signed by all of the parties, which ran counter to ONRR’s long-held position that arm’s-length sales are the best indicator of market value. Fourth, the rule required the Federal oil 20:24 Aug 04, 2017 Jkt 241001 PO 00000 lessees’ affiliates to have all of their contracts, contract revisions, and amendments reduced to writing and signed by all of the parties, despite the fact that the affiliates are not Federal or Indian lessees and the rule was not purporting to regulate them. And fifth, the rule burdened lessees and their affiliates with an unnecessary and potentially costly obligation to conform contracts to meet ONRR’s specifications, which could increase the cost of production and delay the delivery of mineral resources. 5. Valuation Guidance and Determinations The 2017 Valuation Rule required Federal oil and gas and Indian coal lessees to request valuation determinations from ONRR that, because of an oversight in the rule, we would no longer have the regulatory authority to issue. The prior regulations authorized ONRR to issue a binding valuation determination in response to a request from an oil, gas, or coal lessee. The 2017 Valuation Rule, however, inadvertently stripped ONRR of that authority or, at the very least, was unclear as to whether ONRR could continue to exercise that authority. More specifically, sections 1206.108 (Federal oil), 1206.148 (Federal gas), 1206.258 (Federal coal), and 1206.458 (Indian coal) all provided that a lessee could request a valuation determination from ONRR. The rule then provided that ONRR could do one of three things in response to the request: (1) Request that the Assistant Secretary for Policy Management and Budget issue a determination; (2) decide that ONRR will issue non-binding guidance; or (3) notify the lessee that ONRR will not provide a determination or guidance. The rule was silent, however, on whether ONRR could issue a valuation determination in response to a request. Thus, under the 2017 Valuation Rule ONRR arguably had no authority to continue to issue valuation determinations. This was particularly problematic because several sections in the 2017 Valuation Rule required lessees to request valuation determinations from ONRR, and several other provisions required ONRR to issue such determinations. Those references appear in the following sections: Federal coal 1206.111(d) 1206.252(b)(2) 1206.261(c) 1206.268(c) Frm 00005 Fmt 4701 Sfmt 4700 36937 E:\FR\FM\07AUR3.SGM Indian coal 1206.452(b)(2) 1206.461(c) 1206.468(c) 07AUR3 36938 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations Federal gas Federal oil Federal coal Indian coal 1206.160(c) At bottom, this oversight means that lessees cannot comply with the 2017 Valuation Rule and ONRR cannot enforce it, which undermines the purpose and intent of the rule. Even if ONRR could issue valuation determinations in the absence of a regulation, these sections fail to specify whether ONRR’s determinations are binding on ONRR or the lessee, and if so, whether the lessee may appeal the determination. Other provisions of the regulations cross-reference the terms ‘‘valuation determinations’’ and ‘‘determinations’’ without defining those terms or stating whether those terms are synonymous or distinct. In addition, section 1206.458, which applies to Indian coal, incorrectly provides that the Assistant Secretary for Policy, Management and Budget will issue a valuation determination regarding Indian coal. But only the Assistant Secretary for Indian Affairs has the authority to issue a valuation determination for questions concerning Indian lands. All in all, the numerous defects and the lack of consistency in the regulations governing valuation determinations undermined the purpose and intent of the rule and would have created confusion and inefficiencies and imposed additional burdens on both ONRR and the regulated community. sell gas produced from the same lease at arm’s-length, we assumed that the lessee would propose to value its vented and flared gas on the price it received in the arm’s-length sale. Thus, those lessees would have reported one volume, on one line, pursuant to a single valuation method. Lessees in the San Juan Basin in New Mexico, however, would have been held to a different standard. Because there is a viable index price in the San Juan Basin, lessees there would be required to value their gas using the index price. That is true even if the lessee were selling the same gas from the same lease at arm’s length to third-party buyers. Under those circumstances, the lessee would be required to report two separate volumes, on two separate lines, using two separate valuation methods. This inconsistency, and the additional administrative burden it would impose on certain lessees, was not our intent when we promulgated the rule. In sum, the 2017 Valuation Rule would have imposed an unnecessary and potentially costly administrative burden on certain lessees. At the same time, the rule would run counter to ONRR’s long-held belief and position that prices under arm’s-length contracts are the best measure of value. mstockstill on DSK30JT082PROD with RULES3 6. Flared Gas Valuation 7. Changes in Administration and Energy Policy Under the 2017 Valuation Rule, lessees who are required to pay royalty on flared gas would have been required to value the vented and flared gas using an index price for the area if one is available. If an index price were not available, then the lessee would have been required to propose a method to ONRR under the default provision. In those circumstances, we expected that the proposed method would value the vented and flared gas based on the arm’s-length sale price the lessee received for other gas sold from the same lease. ONRR now recognizes that this regulation would have imposed an unnecessary and potentially costly administrative burden on certain lessees. It would also have run counter to ONRR’s belief and position that arm’s-length transactions are the best indicator of value. For example, there is no viable index price in North Dakota. Thus, lessees in North Dakota would have been required to propose a method to ONRR under the default provision. For lessees that also The nation elected a new President in November 2016, and the new administration took office on January 20, 2017. Through various public announcements the new administration quickly signaled that it would adopt and follow a national energy policy different than that of its predecessor, one that emphasized and prioritized the reduction of Federal regulatory burdens on industry. On March 28, 2017, President Donald J. Trump issued E.O. 13783—Promoting Energy Independence and Economic Growth (Executive Order) (82 FR 16093, Mar. 31, 2017). The Executive Order begins by stating broadly that ‘‘[i]t is in the national interest to promote clean and safe development of our Nation’s vast energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production, constrain economic growth, and prevent job creation.’’ The Executive Order then continues, ‘‘Accordingly, it is the policy of the United States that executive VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 PO 00000 Frm 00006 Fmt 4701 Sfmt 4700 departments and agencies (agencies) immediately review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise, or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law.’’ To that end, the Executive Order directs the heads of all agencies to ‘‘review all existing regulations, orders, guidance documents, policies, and any other similar agency actions (collectively, agency actions) that potentially burden the development or use of domestically produced energy resources, with particular attention to oil, natural gas, coal, and nuclear energy resources.’’ The Executive Order defines ‘‘burden’’ to mean ‘‘to unnecessarily obstruct, delay, curtail, or otherwise impose significant costs on the siting, permitting, production, utilization, transmission, or delivery of energy resources.’’ Pursuant to the Executive Order, ONRR included the 2017 Valuation Rule in its review of regulations that potentially burden the development or use of domestically produced energy resources. As a result of that review, we concluded that the rule, as a whole, would unduly burden or unnecessarily obstruct, delay, curtail, or otherwise impose significant costs on the production, utilization, or delivery of Federal oil or gas or Federal or Indian coal. For example, because we realized that valuing coal based on the arm’slength sale of electricity is a very challenging task, we concluded that Federal and Indian coal lessees would incur unnecessary and unwarranted costs in trying to comply with those provisions in the 2017 Valuation Rule. Likewise, because we had realized that the definition of ‘‘coal cooperative’’ in the rule was too broad and ambiguous to comply with or enforce, we concluded that lessees in cooperatives would incur unnecessary and unwarranted costs in an effort to determine the royalty-bearing value of their coal. These defects alone would have resulted in significant costs that would have served as a financial disincentive to producing coal from Federal or Indian lands. In sum, a number of provisions of the 2017 Valuation Rule would have unnecessarily obstructed, delayed, E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations curtailed, or otherwise imposed significant costs on the production, utilization, or delivery of Federal oil and gas and Federal and Indian coal. The repeal of the 2017 Valuation Rule therefore is consistent with the policy announced in the Executive Order and the direction that the Executive Order provides to executive agencies. The Department takes seriously its responsibility to ensure that taxpayers receive the full value from Federal mineral leases, which is why ONRR intends to continue to consider future changes and develop a new rulemaking after further analysis and consultations with our key stakeholders and the general public. mstockstill on DSK30JT082PROD with RULES3 II. Comments on Proposed Rules On April 4, 2017, ONRR published a Notice of Proposed Rulemaking (NPRM) to invite public comment on the possible repeal of the 2017 Valuation Rule. 82 FR 16323. During the 30-day public comment period, we received more than one thousand pages of written comments from over 2,342 commenters. We received comments from industry, industry trade groups, Members of Congress, State governors and agencies, local municipalities, Tribes, local businesses, public interest groups, and individual commenters. The majority of comments—both those opposing and those supporting repeal— addressed the Federal and Indian coal valuation provisions in the 2017 Valuation Rule. Comments opposing repeal of the 2017 Valuation Rule generally argued that repealing the 2017 Valuation Rule would result in undervaluing our nation’s oil, gas, and coal resources; would result in a waste of government resources; and would violate certain provisions in the APA. Comments supporting repeal of the 2017 Valuation Rule generally faulted the following elements of the rule: (a) The method that lessees must use to calculate value on coal sold under nonarm’s-length contracts; (b) ONRR’s definition of ‘‘contract’’ and ‘‘misconduct’’; (c) the default provision; (d) changes to transportation and processing allowances; (e) the option to value Federal gas sold under non-arm’slength transactions based on index prices; and (f) percentage-of-proceeds contracts. A. General Comments Public Comment: Many commenters who work in the coal industry or live in coal-mining-dependent communities, including a tribe, maintained that the 2017 Valuation Rule went too far. They argued that the 2017 Valuation Rule VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 imposed unwarranted valuation methods, which, they contended, hinder transparency and create complex and subjective oil, gas, and coal valuations. They claimed that the 2017 Valuation Rule would cause economic harm to the oil, gas, and coal industries, including the loss of jobs. ONRR also received a few comments advocating that oil, gas, and coal production should stop and that the minerals should ‘‘stay in the ground.’’ ONRR Response: We agree that the 2017 Valuation Rule’s process for using the sale price of electricity to value coal would be too complex to comply with, implement, or enforce. We also agree that other aspects of the 2017 Valuation Rule, including the default provision and the definition of coal cooperative, are too broad to be implemented effectively, which could make reporting and paying royalties more burdensome and less predictable and transparent. Although we appreciate the comments regarding keeping fossil fuels in the ground and the socioeconomic impact of the 2017 Valuation Rule on communities that rely on coal production, both issues are beyond the scope of this rulemaking. Public Comment: An industry trade group commented that complexities in the 2017 Valuation Rule would make it difficult for small businesses to comply. The commenter also claimed that smaller companies would not be able to take deductions, resulting in a higher royalty rate. ONRR Response: For the reasons stated previously, we agree that implementing the rule would increase the costs of compliance and unnecessarily burden the production of Federal and Indian mineral resources. We also agree that those increased compliance costs could disproportionately impact smaller companies that have fewer resources to comply. Public Comment: We received comments from two States asserting that repealing the rule would unfairly reduce the royalties that the States receive under the 2017 Valuation Rule. Conversely, we received a comment from another State asserting that not repealing the rule would result in decreased production that would adversely affect its royalty share. ONRR Response: Based on our economic analysis, we recognize that repealing the 2017 Valuation Rule will result in a decrease in royalties (between 0.8 percent and 1.0 percent) to our State partners compared to what they would receive if ONRR implemented and enforced the rule. ONRR will continue to assess options PO 00000 Frm 00007 Fmt 4701 Sfmt 4700 36939 for updating our valuation regulations and expects to, in the near future, propose new rules that could offset, in whole or in part, the decrease in royalties shared with State partners in future years compared to what would otherwise result from the repeal of the 2017 Valuation Rule. As discussed previously, the rule has a number of defects that make certain provisions challenging to comply with, implement, or enforce. ONRR’s attempt to implement or enforce the rule as written would have compromised our ability to collect and account for mineral royalty revenues, which in turn may have affected distributions to other royalty beneficiaries. It would also have imposed an additional financial and administrative burden on our State and Tribal partners, who audit and verify royalty payments. We also agree with the State commenter that implementing the 2017 Valuation Rule could result in some decreased production, particularly for coal, because the burden of complying with certain provisions of the rule would serve as a disincentive to production. This too would result in decreased royalty distributions to our State and Tribal partners. All told, we believe that the modest economic gains that might result from implementing the rule are far outweighed by the potentially significant burden on industry, ONRR, and our State and Tribal partners from implementing and enforcing a rule with significant defects. Public Comment: Industry trade groups claimed that the 2017 Valuation Rule was unnecessarily complex, which would increase the costs of complying with the regulation. The groups maintained that the complexity and costs would discourage industry from entering into Federal or Indian leases. ONRR Response: ONRR agrees that several unforeseen defects in the 2017 Valuation Rule have the potential to significantly increase the cost and administrative burden of compliance, which could create a disincentive to entering into, and producing oil, gas, and coal from, Federal or Indian leases. Public Comment: We received comments encouraging collaboration with our stakeholders in any future rulemaking. Many industry commenters encouraged working through the RPC to advise ONRR on valuation policies. ONRR Response: As discussed previously, the Secretary has recently re-established the RPC to collaborate with our stakeholders in any future rulemaking. The RPC will provide a forum for engaging with the public on many of the same issues we attempted to address in the 2017 Valuation Rule. E:\FR\FM\07AUR3.SGM 07AUR3 36940 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations C. Administrative Procedure Act (APA) We look forward to working with our stakeholders in the RPC on a future rulemaking. mstockstill on DSK30JT082PROD with RULES3 B. Fair Return to Government Public Comment: Many commenters and comments disagreed about the need either to revise or to repeal the 2017 Valuation Rule. Some public interest groups and some members of the public asserted that ONRR’s regulations have undervalued royalties for many years and that the changes made in the rule would ensure that royalties are based on fair market value. Industry trade groups and other members of the public maintained that the rule would result in values that inflate the value of the resources. ONRR Response: We disagree that repealing the rule will prevent the government from receiving a fair market value for its mineral resources. The prior (and soon-to-be-reinstated) regulations have been in place for more than twenty years and serve as a reasonable, reliable, and consistent method for valuing Federal and Indian minerals for royalty purposes. This is evidenced by the fact that when we promulgated and published the final 2017 Valuation Rule, we estimated that it would generate less than 1 percent in additional royalties. 81 FR 43359. Moreover, as we discussed in proposing the 2017 Valuation Rule, we were attempting to make ‘‘proactive and innovative changes’’ to the rules ‘‘to increase the effectiveness and efficiency of the rules.’’ We believe today, as we always have, that the prior (and soon-tobe-reinstated) regulations provide a fair market return for Federal and Indian minerals. That said, we will continue to look for opportunities to improve our regulations, including opportunities to improve the return to taxpayers and Indian mineral owners and to streamline processes for both ONRR and industry. Public Comment: A public interest group maintained that our regulations should use a market value based on the value of the resource where it is ultimately consumed. The comment asserted that ONRR does not collect royalties at the market and that we should more aggressively pursue a value at the market instead of a value at the lease. ONRR Response: While we appreciate the comment, whether ONRR should use a market value based on the value of the resource where it is ultimately consumed is outside the scope of this rulemaking. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 One member of Congress, two State officials, and several public interest groups asserted that ONRR failed to comply with certain requirements in the APA. Public Comment: Some commenters stated that ONRR’s decision to postpone the effectiveness of the 2017 Valuation Rule indicates ONRR’s intent to repeal the rule, without regard to any comments received in a rulemaking process, in violation of APA rulemaking requirements. ONRR Response: The 2017 Valuation Rule was effective on January 1, 2017. On February 27, 2017, for the reasons discussed in the preamble to this rule, including the filing of three separate petitions challenging the rule in the United States District Court for the District of Wyoming, ONRR postponed the effectiveness of the rule, pending judicial review. 82 FR 11823. ONRR did not decide to repeal the 2017 Valuation Rule, however, until after we had reviewed and considered of all comments that we received in response to the proposed rule of repeal, which we published in the Federal Register on April 4, 2017. 82 FR 16323. Public Comment: We also received comments contending that ONRR did not provide a reasoned basis to repeal the rule. ONRR Response: We are providing a reasoned basis to repeal the rule in the preamble to this rule. Before we proposed to repeal the 2017 Valuation Rule, we identified several defective provisions in the rule that would have made these provisions unnecessarily complicated and burdensome to comply with, implement, or enforce. When we published the proposed rule of repeal on April 4, 2017, we identified some of those defects and specifically invited public comment on them as well as on other aspects of the 2017 Valuation Rule. Public Comment: Public interest groups and some individuals claimed that the 30-day comment period in the NPRM is unreasonable and violates the APA. The commenters asserted that ONRR went to great effort to promulgate the 2017 Valuation Rule and was now proposing to repeal it with only a 30day comment period. ONRR Response: Under the APA’s rulemaking procedures, agencies must publish a notice of proposed rulemaking in the Federal Register; allow interested persons an opportunity to comment on the proposed rule; and, after considering those comments, publish the final rule. The APA requires an opportunity to submit ‘‘written data, views, or PO 00000 Frm 00008 Fmt 4701 Sfmt 4700 arguments,’’ yet there is no required minimum comment period under the APA. See 5 U.S.C. 553(c). Through this rulemaking we are complying with the requirements set forth in the APA. We provided a reasonable amount of time to allow interested parties a sufficient opportunity to consider the repeal and its supporting analysis and to provide meaningful comments. Public Comment: One commenter asserted that ONRR must analyze the record compiled to issue the rule and provide a reasoned explanation for the repeal. According to the commenter, ONRR has not cited any new scientific or technical information in support of repeal. ONRR Response: The comment is not clear on whether it refers to the record for the 2017 Valuation Rule or the record for the repeal of the 2017 Valuation Rule. Regardless, we provided the purpose and justification for both rules and responded to comments that we received during both rulemakings. Specifically, we analyzed the record compiled during the 2017 Valuation Rule rulemaking. 81 FR 43338. In the preamble and responses to comments for this final rule, ONRR also analyzed the record compiled for the proposed repeal. We have determined to repeal the 2017 Valuation Rule for the reasons stated herein. D. Government Efficiency Public Comment: One member of Congress and a public interest group asserted that repealing the rule amounts to wasting government resources because ONRR is abandoning the work that it performed while promulgating the 2017 Valuation Rule. These commenters also argued that if there are problems with the rule, ONRR should address those problems separately and not necessarily abandon the rule in its entirety. ONRR Response: We disagree that repealing the rule is a waste of government resources. As noted previously, the 2017 Valuation Rule has several defects that make certain provisions unnecessarily complicated and burdensome to comply with, implement, or enforce. We have concluded that those defects are significant enough that implementing the rule would compromise our mission to collect and account for mineral royalty revenues for Federal oil and gas and Federal and Indian coal. The cost of implementing the rule and subsequently trying to fix the defects in one or more separate rulemakings would far exceed the cost of repealing and replacing the rule. E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations We also disagree that ONRR is abandoning the work that it previously performed. As noted previously, the Secretary is reestablishing the RPC to increase stakeholder engagement on many of the same issues the 2017 Valuation Rule attempted to address. We hope and expect that this new round of public engagement will lead to the development of a new valuation rule. The work that ONRR performed while promulgating the 2017 Valuation Rule, as well as the stakeholder comments during that rulemaking, will no doubt serve as valuable resources for the RPC as it fulfills its charge to advise ONRR on current and emerging issues related to the determination of fair market value and the collection of royalties from resources on Federal and Indian lands. mstockstill on DSK30JT082PROD with RULES3 E. Federal and Indian Coal Valuation For coal not sold under arm’s-length contracts, the 2017 Valuation Rule removed the ability for lessees to use the benchmarks found in the prior (and soon-to-be-reinstated) regulations. Instead, under the 2017 Valuation Rule lessees had to value their coal on the first arm’s-length sale of the coal. In cases where that first arm’s-length sale was for the sale of electricity, lessees had to use the prices that they received for electricity to ‘‘net back’’ to the value of the coal at the lease. 1. Valuing Coal Based on Benchmarks Public Comment: ONRR received numerous comments from industry, government officials, industry trade groups, public interest groups, and the general public regarding how lessees should value Federal and Indian coal not sold at arm’s length. Some commenters maintained that the prior rule’s non-arm’s-length valuation benchmarks fail to capture the true value of coal that lessees sell in non-arm’s-length transactions. The commenters posited that the benchmarks do not allow ONRR to determine royalty value based on a coal lessee’s affiliate’s subsequent arm’slength sale, including overseas sales, resulting in the coal industries taking advantage of a ‘‘loophole.’’ These commenters maintained that the most effective method to determine the value of Federal and Indian coal not sold under arm’s-length contracts is to use the first arm’s-length sale of coal sold by the lessee’s affiliate. ONRR also received comments from industry, government officials, industry trade groups, and the general public that supported repealing the rule because they found the old benchmarks to be time-tested and robust. These commenters maintained that the 2017 VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 Valuation Rule’s method to determine value for royalty purposes when Federal and Indian lessees do not sell their coal at arm’s-length was difficult to implement and did not establish an appropriate value, for royalty purposes, of Federal or Indian coal at the mine. One commenter asserted that the rule amounted to an unlawful royalty on the value of services that an affiliate provides to the lessee. ONRR Response: We believe that arm’s-length transactions generally are the best indicators of market value because they provide a consistent and accurate measure of value. But we do not agree that the benchmarks in the prior (and soon-to-be-reinstated) regulations create a ‘‘loophole’’ that permits coal lessees to shirk their royalty obligations. Indeed, ONRR has used the benchmarks to order additional royalties due based on an affiliate’s arm’s-length sale, including in those circumstances in which the coal is sold by the affiliate in the international market. While we recognize that the benchmarks are sometimes difficult to apply, we also recognize that benchmarks are a proven and timetested method for determining the fair value of Federal and Indian coal that the lessee does not sell at arm’s-length. 2. Valuing Coal Based on ‘‘Net Back’’ From Electric Sales Public Comment: Numerous coal companies and a coal industry trade group expressed a range of concerns about using electric sales to value coal sold in non-arm’s-length situations without competing economic interests. In particular, these commenters highlighted extraordinary complexities in electric markets and the electric producers’ resource portfolios. They objected to valuing coal by way of electricity, which the commenters asserted is a separate commodity subject to its own unique market factors and forces and regulatory requirements, and argued that geothermal regulations were inappropriate as a means for determining transmission and production allowances. Overall, industry commenters argued that the 2017 Valuation Rule’s effort to value coal through arm’s-length sales of electricity was overly burdensome if not functionally impossible. A number of comments from the general public also asserted that valuing coal as electricity would make electricity more expensive because the increased royalty burden would be passed on to the consumer. ONRR Response: ONRR has carefully considered these comments and, as discussed in the preamble to this rule, has concluded and agrees that the 2017 PO 00000 Frm 00009 Fmt 4701 Sfmt 4700 36941 Valuation Rule’s process for ‘‘netting back’’ to the value of coal from arm’slength electrical sales is an unnecessarily complicated and burdensome task to perform and does not necessarily result in an accurate valuation of the coal. 3. Other Issues Related to Valuing Coal Public Comment: Two companies, one State government representative, three industry trade groups, and one member of the public supporting the repeal observed that the 2017 Valuation Rule handles coal lessees differently than oil and gas lessees and claimed that this treatment is discriminatory. They pointed out that, like coal, gas can be used to generate electricity, but that, unlike coal, ONRR does not require Federal or Indian gas lessees to value their gas production based on electricity sales ‘‘netted back’’ to the lease. ONRR Response: We did not intend to discriminate against coal by valuing the coal based on electricity sales. Coal, oil, and gas are all different commodities, subject to different market factors and forces and regulatory requirements. In our experience, the first arm’s-length sale of much Federal or Indian coal is as electricity. That is rarely the case for Federal or Indian oil and gas. Public Comment: One company suggested that the costs to comply with the 2017 Valuation Rule’s non arm’slength coal valuation provisions would offset any increase in royalty that ONRR would receive. The company further claimed that ONRR’s own analysis shows that the royalties received from these provisions would be minimal if not negative. ONRR Response: We agree that the 2017 Valuation Rule’s requirement to value coal based on electric sales is overly burdensome and would result in substantial compliance costs. F. Definitions 1. Misconduct The 2017 Valuation Rule included a new definition of ‘‘misconduct’’ to use in conjunction with the default provision. Public Comment: One member of the public took issue with the 2017 Valuation Rule’s definition of the term ‘‘misconduct.’’ The commenter maintained that the term has derogatory implications that could affect a lessee’s reputation. The commenter noted that the definition added tension between ONRR and the industry that it regulates. ONRR Response: We defined ‘‘misconduct’’ to clarify when ONRR would use its discretion to determine the value of production under the E:\FR\FM\07AUR3.SGM 07AUR3 36942 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations default provision. We now believe the definition is too ambiguous because it provides almost no guidance as to what type of conduct qualifies as misconduct. At the same time, the rule is silent on whether ONRR must make a formal finding of misconduct before the default provision is invoked, who has the authority make such a finding, and whether such a finding is reviewable on appeal. Taken together, these ambiguities could lead to inconsistent applications of the rule, which would undermine the purpose and intent of the rule. While we cannot surmise how a finding of misconduct would impact a lessee’s reputation, we do agree with the commenter that the ambiguity of the definition perpetuated (and perhaps aggravated) the tension and apprehension that we were attempting to rectify. mstockstill on DSK30JT082PROD with RULES3 2. Coal Cooperative The 2017 Valuation Rule added a new definition of the term ‘‘coal cooperative’’ that included formal or informal organizations of companies or other entities sharing in a common interest to produce and market coal or coal-based products, the latter generally being electricity. Public Comment: One company asserted that, by determining in advance that transactions between coal cooperatives are non-arm’s-length, ONRR failed to take into account its longstanding criteria for determining whether entities are affiliated. The commenter further contended that ONRR has not provided any evidence to support that coal cooperatives are engaging in non-arm’s-length transactions. The company concludes that this is arbitrary, capricious, and contrary to law. ONRR Response: For the reasons discussed in the preamble to this rule, we agree that the definition of coal cooperatives in the 2017 Valuation Rule is overly broad and ambiguous and would create too much confusion to be effective or enforceable. We also agree that the definition is unnecessary because ONRR can evaluate such transactions on a case-by-case basis under the prior (and soon-to-bereinstated) regulations. G. Default Provision The 2017 Valuation Rule included the so-called default provision, which allowed ONRR great discretion to value a lessee’s oil, gas, and coal production in circumstances in which we could not determine whether a lessee properly paid royalties under the regulations. We explained that such circumstances included, but were not limited to, the VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 lessee’s failure to provide documents, the lessee’s misconduct, the lessee’s breach of the duty to market, or any other situation that significantly compromises the Secretary’s ability to reasonably determine the correct value using other measures of value. Public Comment: Companies and industry trade groups overwhelmingly opposed the default provision. Many general public commenters also opposed it. The commenters asserted that the default provision gave ONRR ‘‘overly broad’’ discretion to determine the value of production. An oil and gas industry trade group asserted that the default provision allowed ONRR to ‘‘second guess’’ lessees’ reporting and payment in subsequent years, potentially causing lessees to incur late payment interest and penalties. A State official raised concerns that the default provision could have a chilling effect on coal production from Federal and Indian lands. Public interest groups and other members of the general public approved of the default provision, at least in principle. These commenters asserted that eliminating the default provision would hinder ONRR’s ability to ensure a fair value of Federal and Indian mineral resources, specifically for coal. One public interest group stated that the default provision simply codified the Secretary’s authority to determine royalty value and clarified when and how ONRR anticipated using that authority. ONRR Response: The comments alone demonstrate how the default provision created far more confusion, uncertainty, and apprehension than we intended or anticipated. Under FOGRMA, as amended, the Secretary indisputably has the authority and discretion to determine the reasonable value of Federal and Indian minerals. By promulgating the default provision, we attempted to offer greater clarity, consistency, and predictability by defining when, where, and how ONRR would value production in those circumstances in which we could not determine whether a lessee properly paid royalties under the regulations. We drafted the rule broadly to encompass every scenario in which ONRR would be forced to invoke the default provision. We realize now that in doing so, we provided little in the way of meaningful guidance on how and when ONRR would invoke its authority. Moreover, because the rule was so broad, it created the perception that ONRR would look past the valuation regulations and value production under the default provision regardless of whether the lessee properly reported PO 00000 Frm 00010 Fmt 4701 Sfmt 4700 and paid royalties under our regulations. This widespread confusion defeated the very purpose and intent of including a default provision in the rule. Also, we disagree with those commenters who claimed that eliminating the default provision would hinder ONRR’s ability to ensure a fair value of Federal and Indian mineral resources. Indeed, with or without the default provision, ONRR has the authority to establish the value of Federal and Indian minerals when we cannot determine whether a lessee properly paid royalties under the regulations. ONRR exercised this authority under our prior regulations, and we will continue to exercise that authority now that those regulations will be reinstated. Typically we use this authority in limited circumstances to establish a reasonable value of production using market-based transaction data, which has always been the basis for our royalty valuation rules. Therefore, the repeal of the default provision will have the same small and speculative royalty impact as its implementation. H. Allowances In the 2017 Valuation Rule ONRR eliminated the regulation allowing us to approve transportation allowances in excess of 50 percent of the value of a lessee’s oil production. The rule also eliminated lessees’ ability to net transportation costs in their gross proceeds calculations (‘‘transportation factors’’). The 2017 Valuation Rule also eliminated both our ability to grant extraordinary processing allowances and to approve requests for lessees to exceed the 662⁄3 percent limitation on processing allowances. Public Comment: Coal companies and coal industry trade groups asserted that coal transportation allowances were poorly defined. They also objected to the 2017 Valuation Rule’s requirement that they use the geothermal allowance regulations to ‘‘net back’’ to the value of coal where the first arm’s-length sale is electricity. Oil and gas industry unanimously opposed the rule’s cap on transportation and processing allowances of 50 percent and 662⁄3 percent, respectively. Public interest groups generally opposed repealing the allowance provisions in the 2017 Valuation Rule. Some commenters suggested that allowance caps create more transparency and are easier to enforce. One public interest group advocated for eliminating all allowances, suggesting that they are a form of subsidy. Another public interest group reiterated its view E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations that coal transportation and washing allowances should, like oil and gas, be limited to 50 percent and 662⁄3 percent, respectively. A member of the general public asserted that ONRR should give standard deductions for transportation and coal washing to reduce administrative burden and to ensure a fair return to taxpayers. ONRR Response: We appreciate the variety of responses, but whether ONRR should eliminate all transportation allowances or establish a standard allowance are questions that are outside the scope of this rulemaking. The United States shares in certain expenses that occur downstream or away from the lease, including costs associated with transportation, gas processing, and coal washing, because the United States benefits from lessees selling their production at a market instead of at the lease. We agree that, in practice, the requirement that coal lessees use the geothermal allowance regulations to ‘‘net back’’ to the value of coal where the first arm’s-length sale is electricity is unnecessarily complicated and burdensome. While we disagree that the provisions in the 2017 Valuation Rule that would have capped oil and gas transportation allowances were arbitrary and capricious, we recognize that each cap would impose additional costs on some operators. Public Comment: ONRR received comments from industry trade groups stating that the 2017 Valuation Rule arbitrarily reversed a longstanding deepwater-gathering policy that permitted lessees to take transportation allowances for moving oil and gas production on the OCS. In contrast, a public interest group asserted the deep-water-gathering policy allowed improper deductions under ONRR’s regulatory scheme prior to the 2017 Valuation Rule. The commenter maintained that repealing the 2017 Valuation Rule removes language that ensures appropriate deep-water transportation allowances. ONRR Response: By repealing the 2017 Valuation Rule and reinstating the prior regulations, ONRR’s longstanding deep-water-gathering policy will remain in effect, and ONRR will continue to implement it to the extent that it is consistent with the prior regulations. Nonetheless, ONRR believes that the deep-water-gathering policy is a matter that is appropriate to revisit and reconsider. ONRR will be further considering this matter, including through consultations as part of the RPC process. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 I. Index-Based Gas Valuation Option The 2017 Valuation Rule added an index-price valuation method that lessees who do not sell their gas under an arm’s-length sale could have elected to use in lieu of valuing their gas on their first arm’s-length sale. ONRR based the method on publicly-available index prices, less a specified deduction to account for processing and transportation costs. Public Comment: An industry trade group and a member of the public cited the shortcomings in the index-based gas valuation option as one reason for repealing the 2017 Valuation Rule. While they supported the use of indexbased valuation in concept, they argued that the index-based valuation option in the rule is unreasonable and, at times, arbitrary for the following reasons: (1) ONRR did not provide the option to arm’s-length lessees; (2) the index option could result in a price so high that it would disincentivize lessees from using it; (3) the adjustments for transportation and processing were too low; and (4) ONRR did not provide any standards for when and why it might change the adjustments. ONRR Response: We agree with the commenters that this is an area requiring further analysis. Given the mutual interest in exploring indexbased valuation options, we believe the newly re-commissioned RPC will provide a valuable forum to engage our stakeholders in a meaningful way on this topic. J. Percentage of Proceeds Contracts Lessees sometimes sell their gas under arm’s-length length percentage-ofproceeds (POP) contracts for a price that is based on a specific percentage of the proceeds that the purchaser receives after processing the gas. The 2017 Valuation Rule required lessees with POP contracts to report and pay royalties as processed gas. This rule of repeal allows lessees to report and value POP contract sales as unprocessed gas. Public Comment: An industry trade group maintained that lessees would find it difficult to value gas sold under arm’s-length POP contracts because they lack access to information from the midstream processors and/or purchasers. ONRR Response: Our experience is that the value lessees receive under a POP contract is usually net of certain costs incurred to place the gas into marketable condition. The 2017 Valuation Rule did not change the lessee’s obligation to ensure that it is not deducting costs to place gas in marketable condition at no cost to the PO 00000 Frm 00011 Fmt 4701 Sfmt 4700 36943 Federal government; repealing the rule likewise does not change that obligation. Nonetheless, we believe that how to value gas sold under arm’slength POP contracts is an appropriate topic for the RPC, and we look forward to engaging with members of the public and industry stakeholders to explore different options for reporting POP contracts. K. Requirement of Written, Signed Contracts Although the 2017 Valuation Rule defined ‘‘contract’’ to include legally enforceable oral agreements, the rule itself required a lessee or its affiliate to have all of its contracts, contract revisions or amendments in writing and signed by all of the parties. If the lessee did not have a written contract, signed by all of the parties, then ONRR could use the default provision to determine value. Public Comment: Several commenters disagreed with the 2017 Valuation Rule’s requirement that all contracts for the sale, transportation, processing, or washing of oil, gas, or coal be in writing and signed by all parties to the contract. These commenters maintained that such a restriction ignores that unwritten and unsigned contracts are legally enforceable. ONRR Response: We adopted the requirement that all contracts be in writing and signed by all parties to enhance our ability to verify the accuracy of royalty reports and payments. For the reasons stated in the preamble to this rule, we reconsidered our position and now agree that this provision is unnecessary, overly burdensome, and potentially defective. The prior (and soon-to-be-reinstated) regulations do not require all contracts to be in writing and signed by all parties. But, under 30 CFR 1207.5, we will continue to require lessees to place in written form and maintain copies of all sales contracts and to maintain copies of other contracts and agreements for accounting or auditing purposes. III. Procedural Matters A. Summary Cost and Royalty Impact Data The economic impact analysis that we prepared in the 2017 Valuation Rule used 2010 royalty data. These economic impacts reflected market conditions— commodity price, volumes, etc.—that existed in 2010. In evaluating the economic impacts of repealing the rule, we used more recent royalty data. Using data from 2015 versus 2010 provides an estimate that is more in line with current market projections of future E:\FR\FM\07AUR3.SGM 07AUR3 36944 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations commodity prices. The market for these resources changed between 2010 and 2015, with the value of the resources generally decreasing. Not surprisingly, our updated analysis shows a somewhat smaller decrease in royalty payments compared to the analysis that accompanies the 2017 Valuation Rule. Overall, our estimates for the previous rule, using 2010 data, projected costs to industry of $74.78 million per year (with roughly corresponding benefits to the Treasury and States); this rule, using 2015 data, the projected costs to industry from the 2017 Valuation Rule total $67.4 million per year; thus repeal of the rule results in $67.4 million in benefits to industry (with roughly corresponding benefits to the Treasury and States). We estimated the costs and benefits that this rule will have on all potentially affected groups: Industry, the Federal government, Indian lessors, and State and local governments. This repeal has cost impacts that will result in decreased royalty collections. The net impact of these provisions is an estimated annual decrease in royalty collections of between $60.1 million and $74.8 million. This represents between 0.8 percent and 1.0 percent of the total Federal oil, gas, and coal royalties that we collected in 2015. Although the 2017 Valuation Rule was stayed before the first reporting and payments were due, some lessees had already implemented changes in their related systems and reporting procedures. Therefore, some lessees may incur additional costs from implementing this rule because some lessees may have to undo the system changes that they put in place in anticipation of first reporting under the 2017 Valuation Rule on February 28, 2017. We are unable to quantify that cost at this time. Unless otherwise indicated, the numbers in the following tables are rounded to three significant digits. 1. Industry The table below lists ONRR’s itemized low, mid-range, and high estimates of the costs and benefits that industry would incur in the first year. Industry would receive these benefits in the same amount each year thereafter. SUMMARY OF ROYALTY IMPACTS TO INDUSTRY Rule provision Low Mid High Gas—restore benchmarks: Remove affiliate resale ......................................................................................................... Remove index ....................................................................................................................... NGLs—restore benchmarks: Remove affiliate resale ......................................................................................................... Remove index ....................................................................................................................... Gas transportation 50 percent limitation exceptions reinstated .................................................. Processing allowance 662⁄3 percent limitation exceptions reinstated ......................................... POP contracts processing allowance exceptions of 662⁄3 percent reinstated ............................ Extraordinary processing allowance reinstated ........................................................................... Deep-water-gathering reinstated ................................................................................................. Oil transportation 50 percent limitation exceptions reinstated .................................................... Oil and gas line losses allowance reinstated .............................................................................. BBB bond rate change removed ................................................................................................. Coal—non-arm’s-length netback reinstated ................................................................................ Removing index option administrative costs ............................................................................... Removing deep-water-gathering administrative costs ................................................................ $0 10,600,000 $1,360,000 10,600,000 $2,710,000 10,600,000 0 (2,210,000) 87,000 42,700 9,470,000 14,200,000 23,900,000 0 3,140,000 5,740,000 (1,030,000) (303,000) (3,560,000) 754,000 (2,210,000) 87,000 42,700 9,470,000 14,200,000 28,100,000 0 3,140,000 5,740,000 0 (303,000) (3,560,000) 1,510,000 (2,210,000) 87,000 42,700 9,470,000 14,200,000 32,300,000 0 3,140,000 5,740,000 1,030,000 (303,000) (3,560,000) Total ...................................................................................................................................... 60,100,000 67,400,000 74,800,000 mstockstill on DSK30JT082PROD with RULES3 Note: totals from this table and others in this analysis may not add due to rounding. Benefit—Reinstatement of the Valuation Benchmarks for Non-Arm’s-Length Dispositions of Federal Unprocessed Gas, Residue Gas, and Coalbed Methane To perform this economic analysis, we first extracted royalty data that we collected on residue gas, unprocessed gas, and coalbed methane (product codes 03, 04, and 39, respectively) for calendar year 2015. We did not include 2016 in any of our data sets because lessees are still adjusting their reports for that year and the reported data is still going through ONRR’s edits. We then extracted gas royalty data for non-arm’s-length transactions reported with the sales type code NARM. We also extracted gas royalty data for sales type code POOL because royalty reporters may also use this code to report certain VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 non-arm’s-length transactions. Based on our experience with auditing transactions that use sales type code POOL, only a relatively small portion of transactions are non-arm’s-length. Therefore, we used 10 percent of the POOL volumes in our economic analysis of the volumes of gas sold at non-arm’s length. Based on our experience auditing production sold under non-arm’s-length contracts, we find that industry would incur a royalty decrease between $0.00 and $0.05 per MMBtu under our proposal to use the benchmarks instead of the affiliate’s first arm’s-length resale to value gas production for royalty purposes. We address the royalty impact of the index-based option below. PO 00000 Frm 00012 Fmt 4701 Sfmt 4700 We generated a range of potential royalty decreases by assuming no change in royalties for the low estimate, $0.025 per MMBtu for the mid-range estimate, and $0.05 per MMBtu for the high estimate. We then multiplied the NARM volume and 10 percent of the POOL volume reported to ONRR in 2015 by the potential royalty decrease. The results below are an estimated benefit to industry due to an annual royalty decrease of between zero and approximately $5.4 million. We reduced this estimate by one-half and assumed the mid-point of $0.025 totaling $1.36 million. This assumes that 50 percent of the lessees selling production under non-arm’s-length arrangements would have chosen this option under the 2017 Valuation Rule. E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations 36945 Royalty decrease ($) 2015 MMBtu volume (non-rounded) Low ($0.00) Mid ($0.025) High ($0.05) NARM volume ............................................................................................ 10% POOL volume .................................................................................... 97,869,053 10,614,876 $0 0 $2,446,726 265,372 $4,893,453 530,744 Total .................................................................................................... 108,483,929 0 2,712,098 5,424,196 50% of lessees choose this option ............................................................ .............................. 0 1,360,000 2,710,000 Benefit—Termination of the IndexBased Option To Value Non-Arm’sLength Sales of Federal Unprocessed Gas, Residue Gas, and Coalbed Methane To estimate the royalty impact of removing the index-based option, we calculated a monthly weighted average price net of transportation using NARM and 10 percent of the POOL gas royalty data from seven major geographic areas with active index prices: The Green River Basin, San Juan Basin, Piceance and Uinta Basins, Powder River Basin, Wind River Basin, Permian Basin, and Offshore Gulf of Mexico (GOM). These areas account for approximately 95 percent of all Federal gas produced. To calculate the estimated impact, we performed the following steps: First, identified the Platts Inside FERC highest reported monthly price for the index price applicable to each area— Northwest Pipeline Rockies for Green River, El Paso San Juan for San Juan, Northwest Pipeline Rockies for Piceance and Uinta, Colorado Interstate Gas for Powder River and Wind River, El Paso Permian for Permian, and Henry Hub for GOM. Second, we subtracted the transportation deduction that we specified in the 2017 Valuation Rule from the highest index price that we identified in the first step. Third, we subtracted the average monthly net royalty price reported to us for unprocessed gas from the highest index price for the same month that we calculated in the second step. Fourth, we then multiplied the royalty volume by the monthly difference that we calculated in the third step to calculate a monthly royalty difference for each region. And fifth, we totaled the difference that we calculated in the fourth step for the regions. In 2015, the estimated royalties due using the index-based option was greater than the reported royalties in every month during our analysis. We estimate the benefit to industry due to this change to be a decrease in royalty payments of approximately $10.6 million annually. This estimate represents an average decrease of approximately 9.8 percent, or $0.026 per MMBtu, based on an annual royalty volume of 154,104,793 MMBtu (for NARM and 10 percent POOL reported sales type codes). This would have been the first time that we offered this option; therefore, we did not know how many payors would choose it. We reduced this estimate by one-half, assuming that 50 percent of lessees with non-arm’slength sales would have chosen this option. GOM gas 2015 royalties .............................................................................................................................. Royalty under index option .......................................................................................................... Difference ..................................................................................................................................... Per unit change ($/MMBtu) ......................................................................................................... % Change .................................................................................................................................... 50% of lessees choose this option .............................................................................................. mstockstill on DSK30JT082PROD with RULES3 Benefit—Reinstatement of the Valuation Benchmarks for Non-Arm’s-Length Dispositions of Federal NGLs Like the valuation changes that we discussed previously, for Federal unprocessed, residue, and coalbed methane gas valuation, this rule will value processed Federal NGLs under the prior valuation benchmarks rather than either (1) tracing the first arm’s-length sale or (2) using the index-based option discussed previously. Lessees will no longer have the option to value royalties using an index price value derived from an NGL commercial price bulletin less a theoretical processing allowance that included theoretical transportation and fractionation of the NGLs. We again used the 2015 NARM and POOL NGL data that lessees reported to ONRR for this analysis. We performed the same analysis for valuation using the first arm’s-length sale for Federal unprocessed, residue, and coalbed methane gas, as we discussed. We identified the non-arm’slength volumes that would qualify for this option (for NARM and 10 percent POOL reported sales type codes) and 2015 gallons (rounded to the nearest gallon) NARM volume .................................................................................................. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 PO 00000 Frm 00013 Fmt 4701 Other gas $72,216,537 79,359,207 7,142,670 0.030 9.9% ........................ $143,618,273 157,684,860 14,066,587 0.025 9.8% ........................ $215,834,810 237,044,067 21,209,257 0.026 9.8% 10,600,000 estimated a cents-per-gallon royalty decrease. Based on our experience, we estimate that the NGL resale margin, similar to gas, would range from zero to $0.03 per gallon. Thus, our estimated royalty decrease is zero for the low, $0.015 per gallon for the mid-range, and $0.03 per gallon for the high range. The results below show a mid-range decrease of $754,000 in royalty obligations using these assumptions, and, again, we reduced them by one-half under the assumption that 50 percent of lessees would have chosen this option. Royalty decrease ($) Low ($0.00 cents) 66,911,096 Sfmt 4700 Total E:\FR\FM\07AUR3.SGM $0 07AUR3 Mid ($0.15) High ($0.03) $1,003,666 $2,007,333 36946 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations 2015 gallons (rounded to the nearest gallon) Royalty decrease ($) Low ($0.00 cents) Mid ($0.15) High ($0.03) 10% of POOL volume ...................................................................................... 33,675,717 0 505,136 1,010,272 Total .......................................................................................................... 100,586,813 0 1,508,802 3,017,604 50% of lessees choose this option .................................................................. ........................ 0 754,000 1,510,000 Cost—Termination of the Index-Based Option To Value Non-Arm’s-Length Dispositions of Federal NGLs for all NGLs and the bulletins price each NGL product (such as ethane and propane) separately. Therefore, we calculated a weighted price, or basket price, from the published prices based on typical NGL product volumes, as well as based our analysis on the royalty changes that result from removal of the theoretical processing allowance provided under this option. theoretical processing allowance that includes transportation and fractionation. We used the same 2015 NARM and POOL transaction data for NGLs for this analysis. We were unable to compare NGL prices reported on the form ONRR–2014 to those in commercial price bulletins because the prices that lessees report on the form ONRR–2014 are a single rolled-up price Like the Federal unprocessed, residue, and coalbed methane gas changes that we discussed, lessees will no longer have the option to pay royalties on Federal NGLs production using an index-based value, less a % GOM NGLs $22,292,763 $20,165,669 ($2,127,095) ($0.004) ¥9.5% ........................ 2015 royalties .............................................................................................................................. Royalty under index option .......................................................................................................... Difference ..................................................................................................................................... Per-unit change ($/gal) ................................................................................................................ Percent change ............................................................................................................................ 50% of lessees choose this option .............................................................................................. Cost—Termination of the Index-Based Option To Value Non-Arm’s-Length Federal Unprocessed Gas, Residue Gas, Coalbed Methane, and NGLs ONRR expects that industry will incur additional administrative costs from losing the option to use the index-based option to value non-arm’s-length dispositions of Federal unprocessed gas, residue gas, coalbed methane, and NGLs. Lessees will have to calculate the value of their production using the valuation benchmarks, increasing the time that it takes to calculate the correct price. Lessees will also have to calculate their specific transportation rate for gas, and processing allowance for NGLs, rather than using the ONRR-specified theoretical values. For the 50 percent of lessees that we estimated would use this option, we estimate that eliminating the indexbased option will increase the time burden per line reported by 50 percent to 1.5 minutes for lines that industry electronically submits and 3.5 minutes for lines that they manually submit. In 2015, ONRR received approximately 16 percent more lines than from the data used in the prior rule. We used tables Other NGLs $9,884,982 $7,585,605 ($2,299,378) ($0.008) ¥23.3% ........................ Total $32,177,746 $27,751,273 ($4,426,472) ($0.006) ¥13.8% ($2,210,000) from the Bureau of Labor Statistics (BLS) (https://www.bls.gov/oes/current/ oes132011.htm#nat), which we updated to use current BLS data to estimate the hourly cost for industry accountants in a metropolitan area. We added a multiplier of 1.4 for industry benefits. The industry labor cost factor for accountants will be approximately $53.42 per hour = $38.16 [mean hourly wage] × 1.4 [benefits cost factor]. Using a labor cost factor of $53.42 per hour, we estimate that the annual administrative cost to industry will be approximately $303,000. Estimated lines reported using index option (50%) Electronic reporting (99%) ..................................................................................................... Manual reporting (1%) ........................................................................................................... Industry labor cost/hour ......................................................................................................... 1.5 3.5 .............................. 221,780 2,240 ........................ 5,544 131 $53.42 Total cost to industry ...................................................................................................... mstockstill on DSK30JT082PROD with RULES3 Time burden per line reported (min) .............................. ........................ $303,000 Benefit—Allow Transportation Allowances in Excess of 50 Percent of the Value of Federal Gas Prior to the 2017 Valuation Rule, the Federal gas valuation regulations limited lessees’ transportation allowances to 50 percent of the value of the gas unless they requested and VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 received approval to exceed that limit. The 2017 Valuation Rule eliminated the lessees’ ability to exceed that limit. This rule reinstates the lessees’ ability to request and receive approval to exceed the 50 percent limitation. To estimate the impacts associated with this change, we first identified all calendar year 2015 PO 00000 Frm 00014 Fmt 4701 Sfmt 4700 Annual burden hours reported gas transportation allowances rates that exceeded the 50-percent limit. We then adjusted those allowances down to the 50-percent limit and totaled that value to estimate the economic impact of this provision. The result was an annual estimated benefit to industry of $87,000. E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations Benefit—Allow Transportation Allowances in Excess of 50 Percent of the Value of Federal Oil Prior to the 2017 Valuation Rule, the Federal oil valuation regulations limited lessees’ transportation allowances to 50 percent of the value of the oil unless they requested and received approval to exceed that limit. The 2017 Valuation Rule eliminated the lessees’ ability to exceed that limit. This rule reinstates the lessees’ ability to request and receive approval to exceed the 50percent limitation. To estimate the costs associated with this change, we searched for calendar year 2015reported oil transportation allowance rates that exceeded the 50-percent limit. We did not find any lines for oil transportation that exceeded the 50 percent, so there will be no impact to industry. But companies may exceed the 50-percent limit in the future. 662⁄3-percent limit and totaled that value to estimate the economic impact of this provision. The result was an annual estimated benefit to industry of $42,700. Benefit—Arm’s-Length POP Contracts Not Subject to the 662⁄3 Percent Processing Allowance Limit for Federal Gas In this rule and the rule in effect prior to the 2017 Valuation Rule, lessees with POP contracts paid royalties based on their gross proceeds as long as they paid a minimum value equal to 100 percent of the value of the residue gas. Under the 2017 Valuation Rule, we do not allow lessees with POP contracts to deduct more than the 662⁄3 percent of the value of the NGLs. This rule reinstates the previous regulation’s provision allowing lessees with POP contracts to pay royalties based on their gross proceeds, as long as those gross proceeds are, at a minimum, equal to Benefit—Allow Processing Allowances 100 percent of the value of the residue in Excess of 662⁄3 Percent of the Value gas. For example, a lessee with a 70of the NGLs for Federal Gas percent POP contract receives 70 percent of the value of the residue gas Prior to the 2017 Valuation Rule, the and 70 percent of the value of the NGLs. Federal gas valuation regulations The 30 percent of each product that the limited lessees’ processing allowances to 662⁄3 percent of the value of the NGLs lessee gives up to the processing plant in the past could not, when combined, unless they requested and received exceed an equivalent value of 100 approval to exceed that limit. The 2017 percent of the NGLs’ value. By repealing Valuation Rule eliminated lessees’ ability to exceed that limit. This rule the 2017 Valuation Rule, the combined reinstates the lessees’ ability to request value of each product that the lessee and receive approval to exceed the 662⁄3- gives up to the processing plant could, percent limitation. To estimate the cost again, potentially exceed two-thirds of to industry associated with this change, the NGLs’ value. Lessees report POP contracts to ONRR we first identified all calendar year using sales type codes APOP for arm’s2015-reported processing allowances length POP contracts and NPOP for nongreater than 662⁄3 percent. We then arm’s-length POP contracts. Because adjusted those allowances down to the 36947 lessees report arm’s-length POP contract sales as unprocessed gas, there are no reported processing allowances for us to analyze, and we cannot determine the breakout between residue gas and NGLs. Lessees do report residue gas and NGLs separately for non-arm’s-length POP contracts. However, these reported volumes constitute only 0.07 percent of all the natural gas royalty volumes reported to ONRR. We deemed the nonarm’s-length POP volume to be too low to adequately assess the impact of this provision on both arm’s-length POP and non-arm’s-length POP contracts. Therefore, we examined all reported calendar year 2015 onshore residue gas and NGLs royalty data and assumed that it was processed and that lessees paid royalties as if they sold the residue gas and NGLs under a POP contract. We restricted our analysis to residue gas and NGL volumes produced onshore because we are not aware of any offshore POP contracts. We first totaled the residue gas and NGLs’ royalty value for calendar year 2015 for all onshore royalties. We then assumed that these royalties were subject to a 70-percent POP contract. Based on our experience, a 70/30 split is typical for many POP contracts. We calculated 30 percent of both the value of residue gas and the NGLs to approximate a theoretical 30percent processing deduction. We then compared the 30-percent total of residue gas and NGLs values to 662⁄3 percent of the NGLs value (the maximum allowance under the 2017 Valuation Rule). The table below summarizes these calculations, which we rounded to the nearest dollar: 2015 royalty value prior to allowances 70% 30% $494,401,673 132,618,537 $346,081,171 92,832,976 $148,320,502 39,785,561 Total ........................................................................................................ 627,020,209 438,914,147 188,106,063 66.67% limit ................................................................................................... Difference ....................................................................................................... mstockstill on DSK30JT082PROD with RULES3 Residue gas ................................................................................................... NGLs .............................................................................................................. 88,412,358 99,693,705 (132,618,537 × 2⁄3) ($188,106,063 ¥ $88,412,357) Our analysis shows that the theoretical processing deduction for 30 percent of the value of residue gas and NGLs ($188 million) under our assumed onshore POP contract allowance would exceed the 662⁄3 cap ($88 million) under this rule. In our analysis for the 2017 Valuation Rule, the theoretical deduction did not exceed the allowance cap, and we estimated that this change would result VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 in no impact. The 2015 data, however, did show that the theoretical deduction exceeded the allowance cap, and there will be an economic impact by repealing the 2017 Valuation Rule. This is primarily due to the changing price relationship between gas and NGLs. We estimated that the benefit to industry would be $9.47 million by taking the royalty value that exceeds the POP contract allowance ($100 million) PO 00000 Frm 00015 Fmt 4701 Sfmt 4700 and dividing by the total of non-POP volume (1,582,143,530 MMBtu) to calculate a per-MMBtu rate of $0.06. We then applied the $0.06 rate to the POP contract total volume of 157,764,948 MMBtu to get the estimated increase of $9.47 million. For the sake of this analysis, we assumed that all processing costs incurred were allowable. E:\FR\FM\07AUR3.SGM 07AUR3 36948 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations 2015 MMBtu volume .................................................................................................................. Rate/MMBtu over limit ............................................................................................................... POP MMBtu volume .................................................................................................................. Total impact to industry ............................................................................................................. Benefit— Reinstatement of Policy Allowing Transportation Allowances for Deep-Water-Gathering Systems for Federal Oil and Gas The deep-water-gathering policy discussed previously allows companies to deduct certain expenses for subsea gathering from their royalty payments, even though those costs do not meet ONRR’s definition of transportation. This rule would result in ONRR continuing to apply the policy to the extent that it is consistent with the prior (and soon-to-be-reinstated) regulations. Lessees would therefore be allowed to claim additional allowances, which would decrease their royalties due. To analyze the impact to industry of reinstating this policy, we used data from BSEE’s ArcGIS TIMS (Technical Information Management System) database to estimate that 113 subsea pipeline segments serving 140 leases currently qualify for an allowance under the policy. We assumed all segments were the same—in other words, we did not take into account the size, length, or type of pipeline. For our analysis we also considered only pipeline segments that were in active status and leases in producing status. To determine a range (shown in the tables below as low, mid, and high estimates) for the impact for industry, ONRR estimated a 15 percent error rate in our identification of the 113 eligible pipeline segments, resulting in a range of 96 to 130 eligible pipeline segments. 1,582,143,530 $0.06 157,764,948 $9,470,000 Historical ONRR audit data was available for 13 subsea gathering segments, which served 15 leases covering time periods from 1999 through 2010. We used this data to determine an average initial amount of capital investment in pipeline segments. We used the initial capital investment amount to calculate depreciation and a return on undepreciated capital investment (ROI) for the eligible pipeline segments. We calculated depreciation using a straight-line depreciation schedule based on a 20year useful life of the pipeline. We calculated ROI using 1.0 times the average BBB Bond rate for January 2012, which was the most recent full month of data at the time we performed this analysis. We based the calculations for depreciation and ROI on the first year a pipeline was in service. From the same audit data, we calculated an average annual operating and maintenance (O&M) cost. We increased the O&M cost by 12 percent to account for overhead expenses. Based on experience and audit data, we assumed that 12 percent is a reasonable increase for overhead. We then decreased the total annual O&M cost per pipeline segment by nine percent because an average of nine percent of offshore wellhead oil and gas production is water, which is not royalty bearing. Finally, we used an average royalty rate of 14 percent, which is the volume weighted average royalty rate for all non-Section 6 leases in the Gulf of Mexico. Based on the these ($99,693,705/1,582,143,530) ($.06 × 157,764,948) calculations, the average annual allowance per pipeline segment is approximately $226,664. This represents the estimated amount per pipeline segment ONRR would no longer allow lessees to take as a transportation allowance based on our rescission of the Deep Water Policy in this proposed rulemaking. The total cost to industry would be the $226,664 annual allowance per pipeline segment that we would allow under this proposed rulemaking times the number of eligible segments. To calculate a range for this total, we multiplied the average annual allowance by the low (96), mid (113), and high (130) number of eligible segments. The low, mid, and high annual allowance estimates we would allow are $21.8 million, $25.6 million, and $29.5 million, respectively. Of the currently eligible leases, 56 out of 140, or about 40 percent, qualified for deep water royalty relief under the policy. However, due to varying lease terms, royalty relief programs, price thresholds, volume thresholds, litigation, and other factors, ONRR estimated that only one-half of the 56 leases eligible for royalty relief (20 percent of the 56) actually received royalty relief. Therefore, we decreased the low, mid, and high estimated annual benefit to industry by 20 percent. The table below shows the estimated royalty impact of this section of the proposed rule based on the allowances we will allow under this rule. Low Estimated Royalty Impact ............................................................................................................ mstockstill on DSK30JT082PROD with RULES3 Cost—Reinstatement of Policy Allowing Transportation Allowances for DeepWater- Gathering Systems for Federal Oil and Gas We estimate the restoration of transportation allowances for deepwater-gathering systems would eliminate the industry administrative benefit under the 2017 Valuation Rule as lessees would have to perform this VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 calculation. We assume that the cost to perform this calculation is significant because in our experience industry has often hired outside consultants to calculate their subsea transportation allowances. Using this information, we estimate each company with leases eligible for transportation allowances for deep water gathering systems would allocate one full-time FTE annually to perform this calculation, whether they PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 Mid High $23,900,000 $28,100,000 $32,300,000 use consultants or perform the calculation in-house. We used the Bureau of Labor Statistics to estimate the hourly cost for industry accountants in a metropolitan area ($38.16 mean hourly wage) with a multiplier of 1.4 for industry benefits to equal approximately $53.42 per hour ($38.16 × 1.4). Using this labor cost per hour, we estimate the annual administrative cost to industry would be approximately: E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations 36949 Annual burden hours per company Industry labor cost/hour Companies reporting eligible leases Estimated cost to industry 2,080 $53.42 32 $3,560,000 Deep Water Gathering ..................................................................................... Benefit—Reinstating Extraordinary Processing Cost Allowances for Federal Gas As we discussed previously, we are reinstating the provision in our regulations that allows lessees to request an extraordinary processing cost allowance and to allow any extraordinary processing cost allowances that we previously granted. We have granted two such approvals in the past, so we know the lease universe that is claiming this allowance and were able to retrieve the processing allowance data that lessees deducted from the value of residue gas produced from the leases. We then calculated the annual total processing allowance that lessees have claimed for 2012 through 2015 for the leases at issue. We then averaged the yearly totals for those four years to estimate an annual benefit to industry of $14.2 million in decreased royalties. Benefit—Increasing the Rate of Return Used To Calculate Non-Arm’s-Length Transportation Allowances From 1 to 1.3 Times the Standard and Poor’s BBB Bond for Federal Oil and Gas mstockstill on DSK30JT082PROD with RULES3 For Federal oil transportation, we do not maintain or request data identifying whether transportation allowances are arm’s length or non-arm’s length. However, in our experience, lessees transport a significant portion of Gulf of Mexico (GOM) oil through their own pipelines. In addition, many onshore transportation allowances include costs of trucking and rail and, most likely, this change would not impact those. Therefore, to calculate the costs associated with this change, we assumed that 50 percent of the GOM transportation allowances are non-arm’s length and that ten percent of transportation allowances everywhere else (onshore and offshore other than the GOM) are non-arm’s length. We also assumed that, over the life of the pipeline, allowance rates are made up of one-third rate of return on undepreciated capital investment, onethird depreciation expenses, and onethird operation, maintenance, and overhead expenses. In 2015, the total oil transportation allowances that Federal lessees deducted were approximately $100 million from the GOM and $12.5 million from everywhere else. Based on these totals and our assumptions regarding the makeup of the allowance components, the portion of the nonarm’s-length allowances attributable to the rate of return will be approximately $16,600,000 for the GOM ($100,000,000 × 1⁄3 × 50%) and $416,000 ($12,500,000 × 1⁄3 × 10%) for the rest of the country. Based on these assumptions, industry will receive an increase in yearly oil transportation allowance deductions of approximately $3,920,000 ($17,000,000 × (1.3 ¥ 1.0)/1.3). That is, we estimate that the net benefit to industry for oil transportation allowances as a result of this change will be an approximately $3,920,000 in decreased royalties due. Like Federal oil, we do not maintain or request information on whether Federal gas transportation allowances are arm’s-length or non-arm’s length. However, unlike Federal oil, in our experience, it is not common for GOM gas to be transported through lesseeowned pipelines. Therefore, we assumed that only 10 percent of all gas transportation allowances are non-arm’s length and made no distinction between the GOM and everywhere else. All other assumptions for natural gas are the same as those that we made for oil. In 2015, the total gas transportation allowances that Federal lessees deducted were approximately $238 million. Based on that total and our assumptions regarding the makeup of the allowance components, the portion of the non-arm’s-length allowances attributable to the rate of return will be approximately $7.93 million ($238,000,000 × 1⁄3 × 10%). Therefore, industry will see an increase in yearly gas transportation allowance deductions of approximately $1.82 million ($7.93 million × (1.3 ¥ 1.0)/1.3). That is, the net decreased cost to industry for gas transportation allowances will be approximately $1,820,000. The combined impact to industry for this change will be $5,740,000 in decreased royalties due. No Change—Disallow a Rate of Return on Reasonable Salvage Value for Federal Oil, Gas, and Coal In the 2017 Valuation Rule, ONRR estimated that this provision would have no impact to industry. ONRR likewise estimates that the repeal has no impact. Benefit—Allow Line Loss as a Component of Non-Arm’s-Length Oil and Gas Transportation This rule also reinstates the regulatory provision allowing lessees to deduct the costs of pipeline losses, both actual and theoretical, when calculating non-arm’slength transportation allowances. For this analysis, we assumed that pipeline losses are 0.2 percent of the volume transported through the pipeline, based on a survey of pipeline tariff. This 0.2 percent of the volume transported would also equate to 0.2 percent of the value of the Federal royalty volume of oil and gas production transported. For Federal oil produced in calendar year 2015, the Federal royalty value subject to transportation allowances was $2,746,256,148 in the GOM and $1,039,271,142 everywhere else. Using our previous assumption that 50 percent of GOM and 10 percent of everywhere else’s transportation allowances are non-arm’s length, we estimated that the value of the line loss will be $2.96 million, as we detailed in the table below. Therefore, the annual benefit to industry will be approximately $2.96 million. OIL LINE LOSS ROYALTY IMPACT Line loss % 50% of GOM royalty value ...................................................................................................... 10% of everywhere else royalty value .................................................................................... VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 PO 00000 Frm 00017 Fmt 4701 Sfmt 4700 $1,373,128,209 103,927,114 E:\FR\FM\07AUR3.SGM 07AUR3 0.2 0.2 Royalty decrease $2,750,000 208,000 36950 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations OIL LINE LOSS ROYALTY IMPACT—Continued Line loss % Total .................................................................................................................................. For Federal gas produced in calendar year 2015, the Federal gas royalty value subject to transportation allowances was Royalty decrease 2,960,000 $888,676,828. Using our previous assumption that 10 percent of Federal gas transportation allowances are non- arm’s length, we estimated that the value of the line loss and annual benefit to industry would be $178,000. GAS LINE LOSS ROYALTY IMPACT Line loss % 10% of royalty value ................................................................................................................ The total estimated royalty decrease for both oil and gas due to this change will be $3.14 million [$2,960,000 (oil) plus $178,000 (gas) = $3,140,000]. Benefit—Depreciating Oil Pipeline Assets Only Once Under the non-arm’s-length transportation allowance section of this rule and the rule in effect prior to the 2017 Valuation Rule, for Federal oil, if an oil pipeline is sold, the purchasing company might use the purchase price to establish a new depreciation schedule, provided that the purchasing company is a royalty payor claiming a non-arm’s-length transportation allowance. In theory, this change results in additional royalty savings for companies. However, based on our experience monitoring the oil markets, we find that the sale of oil pipeline assets is rare. We are also not aware of any planned future sales of oil pipelines that this rule change will impact. Therefore, although there will be a benefit to industry under this rule, we cannot quantify the cost at this time. mstockstill on DSK30JT082PROD with RULES3 No Change—Eliminating the Use of the First Arm’s-Length Sale to Value NonArm’s-Length Sales of Federal Coal and Sales of Federal Coal Between Parties That Lack Opposing Economic Interest—‘‘Coal Cooperatives’’ in the 2017 Valuation Rule In the 2017 Valuation Rule, ONRR did not estimate any impacts to industry for the change in regulations for this provision. This repeal will reinstate the valuation regulations as they were prior to the 2017 Valuation Rule’s publication. Therefore, ONRR does not estimate any impact to industry at this time. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 $88,867,683 No Change—Eliminating the Use of Arm’s-Length Electricity Sales to Value Non-Arm’s-Length Dispositions of Federal Coal and Dispositions of Federal Coal Parties That Lack Opposing Economic Interest—‘‘Coal Cooperatives’’ in the 2017 Valuation Rule In the 2017 Valuation Rule, ONRR did not estimate any impacts to industry for the change in regulations for this provision. This repeal will reinstate the valuation regulations as they were prior to the 2017 Valuation Rule’s publication. Therefore, ONRR does not estimate any impact to industry at this time. No Change—Eliminating the Default Provision to Value Non-Arm’s-Length Sales of Federal Coal in Lieu of Sales of Electricity For these situations, valuation of Federal coal will be determined under the non-arm’s-length benchmarks after this repeal of the 2017 Valuation Rule. Because the default provision establishes a valuation method that approximates the market value of the coal very similar to the benchmarks, we estimate that the royalty effect of this rule on lessees of Federal coal will be nominal. No Change—Using the First Arm’sLength Sale to Value Non-Arm’s-Length Sales of Indian Coal In the 2017 Valuation Rule, ONRR did not estimate any impacts to industry for the change in regulations for this provision. This repeal will reinstate the valuation regulations as they were prior to the 2017 Valuation Rule’s publication. Therefore, we do not estimate any impact to industry at this time. PO 00000 Frm 00018 Fmt 4701 Sfmt 4700 Royalty decrease 0.2 $178,000 No Change—Using Sales of Electricity to Value Non-Arm’s-Length Sales of Indian Coal In the 2017 Valuation Rule, ONRR did not estimate any impacts to industry for the change in regulations for this provision. This repeal will reinstate the valuation regulations as they were prior to the 2017 Valuation Rule’s publication. Therefore, we do not estimate any impact to industry at this time. No Change—Using First Arm’s-Length Sale to Value Sales of Indian Coal Between Coal Cooperative Members In the 2017 Valuation Rule, ONRR did not estimate any impacts to industry for the change in regulations for this provision. This repeal will reinstate the valuation regulations as they were prior to the 2017 Valuation Rule’s publication. Therefore, we do not estimate any impact to industry at this time. No Change—Elimination of the Default Provision to Value Federal Oil, Gas, and Coal and Indian Coal In the 2017 Valuation Rule, we anticipated that we would have used the default provision only in specific cases where conventional valuation procedures have not worked to establish a value for royalty purposes. We also stated that assigning a royalty impact figure to any of the instances where we would have used the default provisions was speculative because (1) each instance would have been case-specific, (2) we could not anticipate when we would have used the option, and (3) we could not anticipate the value that we would have required companies to pay. Additionally, we estimated that the royalty impact would have been relatively small because the default provision would always have established a reasonable value of E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations production using market-based transaction data, which has always been the basis for our royalty valuation rules. Therefore, removal of the default provision will have a similarly small and speculative royalty difference. 2. State and Local Governments We estimate that the States and local governments that this rule impacts will incur a decrease in royalty receipts. The details of this impact are outlined below. States and local governments receiving revenues for offshore Outer Continental Shelf Lands Act Section 8(g) leases will continue to receive royalties as under the regulations preceding the 2017 Valuation Rule, as will States receiving revenues from onshore Federal lands. Based on the ratio of Federal revenues disbursed to States and local governments for section 8(g) leases and the onshore States we detail in the table below, ONRR assumed the same proportion of revenue decreases for each proposal that will impact those State revenues for most of the provisions. 36951 royalties as a result of these changes. The royalty decrease incurred by the Federal government will be the difference between the total royalty OnOffshore 8(g) shore decrease to industry and the royalty % % % decrease affecting the States and local governments. The net yearly impact on Federal .............. 50 100 73 State ................. 50 0 0 the Federal government will be Section 8(g) ...... 0 0 27 approximately $55.8 million, which we detail in section (5) below. Some provisions of this rule affect 5. Summary of Royalty Impacts and Federal, State, and local government Costs to Industry, State and Local revenues, while others, such as Governments, Indian Lessors, and the reinstating extraordinary processing cost Federal Government allowances, affect only onshore States’ In the table below, the negative values and Federal revenues. The table in the industry column represent their summarizing the State and local estimated royalty collection decrease for government royalty decreases that we Federal, State, and local governments, provide in section 5 details these while the positive values in the other differences. columns represent the increase in 3. Indian Lessors royalty savings for industry. Please note that the estimated impacts to Federal, ONRR estimates that the changes to the coal regulations that apply to Indian State, and local governments do not include the administrative savings lessors will have no impact on their provisions of the economic analysis royalties. discussed above. Those provisions are 4. Federal Government only realized by industry. For the The impact to the Federal purposes of this summary table, we government, like the States and local used the midpoint estimates for these governments, will be a net decrease in impacts. ROYALTY DISTRIBUTIONS BY LEASE TYPE Rule Provision Industry Gas—restore benchmarks: Remove affiliate Resale ............................................................................ Remove index ........................................................................................... NGLs—restore benchmarks: Remove affiliate Resale ............................................................................ Remove index ........................................................................................... Gas transportation 50% limitation exceptions reinstated ................................ Processing allowance 662⁄3% limitation exceptions reinstated ....................... POP contracts’ processing allowance exceptions of 662⁄3% limitation reinstated ............................................................................................................ Extraordinary processing allowance reinstated ............................................... Deep-water-gathering reinstated ..................................................................... Oil transportation 50% limitation exceptions reinstated .................................. Oil and gas line losses allowance reinstated .................................................. BBB bond rate change removed ..................................................................... Coal provisions ................................................................................................ Total .......................................................................................................... Federal State State 8(g) $1,360,000 $10,600,000 ($865,000) ($6,750,000) ($483,000) ($3,760,000) ($11,600) ($90,600) $754,000 ($2,210,000) $87,000 $42,700 ($529,000) $1,550,000 ($55,400) ($29,900) ($220,000) $646,000 ($30,900) ($12,500) ($4,830) $14,200 ($744) ($274) $9,470,000 $14,200,000 $28,100,000 $0 $3,140,000 $5,740,000 $0 ($6,640,000) ($7,100,000) ($28,100,000) $0 ($2,560,000) ($4,680,000) $0 ($2,770,000) ($7,100,000) $0 $0 ($562,000) ($1,030,000) $0 ($60,700) $0 $0 $0 ($17,200) ($31,500) $0 $71,300,000 ($55,800,000) ($15,300,000) ($200,000) Note: totals from this table and others in this analysis may not add due to rounding. mstockstill on DSK30JT082PROD with RULES3 B. Regulatory Planning and Review (Executive Orders 12866 and 13563 and Executive Order 13771 on Reducing Regulation and Controlling Regulatory Costs Dated January 30, 2017) Executive Order (E.O.) 12866 provides that the Office of Information and Regulatory Affairs (OIRA) of the Office of Management and Budget (OMB) will review all significant rules. OIRA has determined that this rule is significant because it may materially alter the budgetary impact of entitlements, grants, user fees, or loan programs or the VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 rights and obligations of recipients thereof. Executive Order 13563 reaffirms the principles of E.O. 12866, while calling for improvements in the Nation’s regulatory system to promote predictability, to reduce uncertainty, and to use the best, most innovative, and least burdensome tools for achieving regulatory ends. This Executive Order directs agencies to consider regulatory approaches that reduce burdens and maintain flexibility and freedom of choice for the public where these approaches are relevant, PO 00000 Frm 00019 Fmt 4701 Sfmt 4700 feasible, and consistent with regulatory objectives. E.O. 13563 emphasizes further that regulations must be based on the best available science and that the rulemaking process must allow for public participation and an open exchange of ideas. We developed this rule in a manner consistent with these requirements. This final rule is considered a deregulatory action under E.O. 13771, Reducing Regulation and Controlling Regulatory Costs (82 FR 9339, Feb. 3, 2017). Although there are some costs to industry associated with this rule, the E:\FR\FM\07AUR3.SGM 07AUR3 36952 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations rule still results in an overall savings to industry. Details on the estimated savings and costs associated with the rule can be found in the rule’s economic analysis. C. Regulatory Flexibility Act mstockstill on DSK30JT082PROD with RULES3 The Department of the Interior (Department) certifies that this rule will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.). See the 2017 Valuation Rule, Procedural Matters, item 1, starting at 81 FR 43359, and item 3, starting at 81 FR 43367. This rule will affect only lessees under Federal oil and gas leases and Federal and Indian coal leases. The Department certifies that this rule will not have a significant economic effect on a substantial number of small entities under the Regulatory Flexibility Act (5 U.S.C. 601 et seq.), see item 1 above for the analysis. This rule will affect lessees under Federal oil and gas leases and Federal and Indian coal leases. Federal and Indian mineral lessees are, generally, companies classified under the North American Industry Classification System (NAICS), as follows: • Code 211111, which includes companies that extract crude petroleum and natural gas • Code 212111, which includes companies that extract surface coal • Code 212112, which includes companies that extract underground coal For these NAICS code classifications, a small company is one with fewer than 500 employees. Approximately 1,920 different companies submit royalty and production reports from Federal oil and gas leases and Federal and Indian coal leases to us each month. Of these, approximately 65 companies are large businesses under the U.S. Small Business Administration definition because they have more than 500 employees. The Department estimates that the remaining 1,855 companies that this rule affects are small businesses. As we stated earlier, based on 2015 sales data, this rule is a benefit to industry of approximately $71 million dollars per year. Small businesses accounted for about 20 percent of the royalties paid in 2015. Applying that percentage to industry costs, we estimate that this final rule will benefit all small-business lessors approximately $14,200,000 per year. The amount will vary for each company depending on the volume of production that each small business produces and sells each year. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 In sum, we do not estimate that this rule will result in a significant economic effect on a substantial number of small entities because this rule will benefit affected small businesses a collective total of $14,200,000 per year. D. Small Business Regulatory Enforcement Fairness Act This rule is not a major rule under 5 U.S.C. 804(2), the Small Business Regulatory Enforcement Fairness Act. This rule: (1) Does not have an annual effect on the economy of $100 million or more. We estimate that industry will annually benefit between $60,100,000 and $74,800,000. These figures are a reversal of the impacts described in the 2017 Valuation Rule, under Procedural Matters, item 1, starting at 81 FR 43359, and item 4, 81 FR 43368, but has been adjusted to include more current data. Therefore, the economic impact on industry, State and local governments and the Federal government will be below the $100 million threshold that the Federal government uses to define a rule as having a significant impact on the economy. (2) Will not cause a major increase in costs or prices for consumers; individual industries; Federal, State, or local government agencies; or geographic regions. See Procedural Matters, item 1. (3) Does not have significant adverse effects on competition, employment, investment, productivity, innovation, or the ability of U S-based enterprises to compete with foreign-based enterprises. This rule will benefit U.S.-based enterprises. E. Unfunded Mandates Reform Act This rule does not impose an unfunded mandate on State, local, or Tribal governments or the private sector of more than $100 million per year. This rule does not have a significant or unique effect on State, local, or Tribal governments or the private sector. Therefore, we are not required to provide a statement containing the information that the Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) requires. See Procedural Matters, item 1. F. Takings (E.O. 12630) Under the criteria in section 2 of E.O. 12630, this rule does not have any significant takings implications. This rule will not impose conditions or limitations on the use of any private property. This rule will apply to Federal oil, Federal gas, Federal coal, and Indian coal leases only. Therefore, this rule PO 00000 Frm 00020 Fmt 4701 Sfmt 4700 does not require a Takings Implication Assessment. G. Federalism (E.O. 13132) Under the criteria in section 1 of E.O. 13132, this rule does not have sufficient Federalism implications to warrant the preparation of a Federalism assessment. The management of Federal oil and gas leases, and Federal and Indian coal leases is the responsibility of the Secretary of the Interior. This rule does not impose administrative costs on States or local governments. This rule also does not substantially and directly affect the relationship between the Federal and State governments. Because this rule does not alter that relationship, this rule does not require a Federalism summary impact statement. H. Civil Justice Reform (E.O. 12988) This rule complies with the requirements of E.O. 12988. Specifically, this rule: (a) Meets the criteria of § 3(a), which requires that we review all regulations to eliminate errors and ambiguity and write them to minimize litigation. (b) Meets the criteria of § 3(b)(2), which requires that we write all regulations in clear language using clear legal standards. I. Consultation With Indian Tribes (E.O. 13175 and Departmental Policy) The Department strives to strengthen its government-to-government relationship with Indian Tribes through a commitment to consultation with Indian Tribes and recognition of their right to self-governance and Tribal sovereignty. Under the criteria in E.O. 13175, we evaluated this final rule and determined that it will have no potential effects on Federally-recognized Indian Tribes. Specifically, we determined that this rule will restore the historical valuation methodology for coal produced from Indian leases. Accordingly: (1) We mailed letters, on April 3, 2017, to the Crow Tribe of Montana, Hopi Tribe of Arizona, and Navajo Nation to consult with the Tribes on both the Notice of Proposed Rulemaking and Advance Notice of Proposed Rulemaking for the proposed repeal of 2017 Indian coal valuation regulations. (2) We consulted with the Navajo Nation on May 24, 2017, in Window Rock, Arizona. (3) We consulted with the Crow Tribe on May 26, 2017, in Crow Agency, Montana. (4) We consulted with the Hopi on June 21, 2017, in Kykotsmovi, Arizona. E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations J. Paperwork Reduction Act This rule: (1) Does not contain any new information collection requirements. (2) Does not require a submission to the OMB under the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et seq.). See 5 CFR 1320.4(a)(2). This rule will leave intact the information collection requirements that OMB already approved under OMB Control Numbers 1012–0004, 1012– 0005, and 1012–0010. K. National Environmental Policy Act This rule does not constitute a major Federal action significantly affecting the quality of the human environment. We are not required to provide a detailed statement under the National Environmental Policy Act of 1969 (NEPA) because this rule qualifies for a categorical exclusion under 43 CFR 46.210(i) in that this is ‘‘. . . of an administrative, financial, legal, technical, or procedural nature. . . .’’ This rule also qualifies for categorically exclusion under Departmental Manual, part 516, section 15.4.(C)(1) in that its impacts are limited to administrative, economic, or technological effects. We also have determined that this rule is not involved in any of the extraordinary circumstances listed in 43 CFR 46.215 that require further analysis under NEPA. The procedural changes resulting from the repeal of the 2017 Valuation Rule will have no consequence on the physical environment. This rule does not alter, in any material way, natural resources exploration, production, or transportation. L. Effects on the Nation’s Energy Supply (E.O. 13211) This rule is not a significant energy action under the definition in E.O. 13211; therefore, a Statement of Energy Effects is not required. List of Subjects mstockstill on DSK30JT082PROD with RULES3 30 CFR Part 1202 Coal, Continental shelf, Government contracts, Indian lands, Mineral royalties, Natural gas, Oil and gas exploration, Public lands—mineral resources, Reporting and recordkeeping requirements. 30 CFR Part 1206 Coal, Continental shelf, Government contracts, Indian lands, Mineral royalties, Oil and gas exploration, Public lands—mineral resources, VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 Reporting and recordkeeping requirements. Gregory J. Gould, Director for Office of Natural Resources Revenue. Authority and Issuance For the reasons discussed in the preamble, ONRR amends 30 CFR parts 1202 and 1206 as set forth below: PART 1202—ROYALTIES 1. The authority citation for part 1202 continues to read as follows: ■ Authority: 5 U.S.C. 301 et seq., 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.,1331 et seq., and 1801 et seq. Subpart B—Oil, Gas, and OCS Sulfur, General 2. In § 1202.51, revise paragraph (b) to read as follows: ■ § 1202.51 Scope and definitions. * * * * * (b) The definitions in subparts B, C, D, and E of part 1206 of this title are applicable to subparts B, C, D, and J of this part. Subpart F—Coal ■ 3. Remove § 1202.251. PART 1206—PRODUCT VALUATION 4. The authority citation for part 1206 continues to read as follows: ■ Authority: 5 U.S.C. 301 et seq., 25 U.S.C. 396 et seq., 396a et seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et seq., and 1801 et seq. 5. Revise subpart A, consisting of § 1206.10, to read as follows: ■ Subpart A—General Provisions and Definitions § 1206.10 Information collection. The information collection requirements contained in this part have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance numbers are identified in § 1210.10. ■ 6. Revise subpart C to read as follows: Subpart C—Federal Oil Sec. 1206.100 What is the purpose of this subpart? 1206.101 What definitions apply to this subpart? 1206.102 How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm’s-length contract? PO 00000 Frm 00021 Fmt 4701 Sfmt 4700 36953 1206.103 How do I value oil that is not sold under an arm’s-length contract? 1206.104 What publications are acceptable to ONRR? 1206.105 What records must I keep to support my calculations of value under this subpart? 1206.106 What are my responsibilities to place production into marketable condition and to market production? 1206.107 How do I request a value determination? 1206.108 Does ONRR protect information I provide? 1206.109 When may I take a transportation allowance in determining value? 1206.110 How do I determine a transportation allowance under an arm’slength transportation contract? 1206.111 How do I determine a transportation allowance if I do not have an arm’s-length transportation contract or arm’s-length tariff? 1206.112 What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices? 1206.113 How will ONRR identify market centers? 1206.114 What are my reporting requirements under an arm’s-length transportation contract? 1206.115 What are my reporting requirements under a non-arm’s-length transportation arrangement? 1206.116 What interest applies if I improperly report a transportation allowance? 1206.117 What reporting adjustments must I make for transportation allowances? 1206.119 How are the royalty quantity and quality determined? 1206.120 How are operating allowances determined? Subpart C—Federal Oil § 1206.100 subpart? What is the purpose of this (a) This subpart applies to all oil produced from Federal oil and gas leases onshore and on the Outer Continental Shelf (OCS). It explains how you as a lessee must calculate the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws, and lease terms. (b) If you are a designee and if you dispose of production on behalf of a lessee, the terms ‘‘you’’ and ‘‘your’’ in this subpart refer to you and not to the lessee. In this circumstance, you must determine and report royalty value for the lessee’s oil by applying the rules in this subpart to your disposition of the lessee’s oil. (c) If you are a designee and only report for a lessee, and do not dispose of the lessee’s production, references to ‘‘you’’ and ‘‘your’’ in this subpart refer to the lessee and not the designee. In this circumstance, you as a designee E:\FR\FM\07AUR3.SGM 07AUR3 36954 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations must determine and report royalty value for the lessee’s oil by applying the rules in this subpart to the lessee’s disposition of its oil. (d) If the regulations in this subpart are inconsistent with: (1) A Federal statute; (2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation; (3) A written agreement between the lessee and the ONRR Director establishing a method to determine the value of production from any lease that ONRR expects at least would approximate the value established under this subpart; or (4) An express provision of an oil and gas lease subject to this subpart, then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency. (e) ONRR may audit and adjust all royalty payments. mstockstill on DSK30JT082PROD with RULES3 § 1206.101 subpart? What definitions apply to this The following definitions apply to this subpart: Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart: (1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that ONRR may rebut. (2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, ONRR will consider the following factors in determining whether there is control under the circumstances of a particular case: (i) The extent to which there are common officers or directors; (ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: the percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership; (iii) Operation of a lease, plant, or other facility; (iv) The extent of participation by other owners in operations and day-today management of a lease, plant, or other facility; and VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 (v) Other evidence of power to exercise control over or common control with another person. (3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates. ANS means Alaska North Slope (ANS). Area means a geographic region at least as large as the limits of an oil field, in which oil has similar quality, economic, and legal characteristics. Arm’s-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm’s length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed. Audit means a review, conducted under generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees, designees or other persons who pay royalties, rents, or bonuses on Federal leases. BLM means the Bureau of Land Management of the Department of the Interior. BOEM means the Bureau of Ocean Energy Management of the Department of the Interior. BSEE means the Bureau of Safety and Environmental Enforcement of the Department of the Interior. Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without processing. Condensate is the mixture of liquid hydrocarbons resulting from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir. Contract means any oral or written agreement, including amendments or revisions, between two or more persons, that is enforceable by law and that with due consideration creates an obligation. Designee means the person the lessee designates to report and pay the lessee’s royalties for a lease. Exchange agreement means an agreement where one person agrees to deliver oil to another person at a specified location in exchange for oil deliveries at another location. Exchange agreements may or may not specify prices for the oil involved. They frequently specify dollar amounts reflecting location, quality, or other differentials. Exchange agreements include buy/sell agreements, which specify prices to be paid at each exchange point and may appear to be PO 00000 Frm 00022 Fmt 4701 Sfmt 4700 two separate sales within the same agreement. Examples of other types of exchange agreements include, but are not limited to, exchanges of produced oil for specific types of crude oil (e.g., West Texas Intermediate); exchanges of produced oil for other crude oil at other locations (Location Trades); exchanges of produced oil for other grades of oil (Grade Trades); and multi-party exchanges. Field means a geographic region situated over one or more subsurface oil and gas reservoirs and encompassing at least the outermost boundaries of all oil and gas accumulations known within those reservoirs, vertically projected to the land surface. State oil and gas regulatory agencies usually name onshore fields and designate their official boundaries. BOEM names and designates boundaries of OCS fields. Gathering means the movement of lease production to a central accumulation or treatment point on the lease, unit, or communitized area, or to a central accumulation or treatment point off the lease, unit, or communitized area that BLM or BSEE approves for onshore and offshore leases, respectively. Gross proceeds means the total monies and other consideration accruing for the disposition of oil produced. Gross proceeds also include, but are not limited to, the following examples: (1) Payments for services such as dehydration, marketing, measurement, or gathering which the lessee must perform at no cost to the Federal Government; (2) The value of services, such as salt water disposal, that the producer normally performs but that the buyer performs on the producer’s behalf; (3) Reimbursements for harboring or terminaling fees; (4) Tax reimbursements, even though the Federal royalty interest may be exempt from taxation; (5) Payments made to reduce or buy down the purchase price of oil to be produced in later periods, by allocating such payments over the production whose price the payment reduces and including the allocated amounts as proceeds for the production as it occurs; and (6) Monies and all other consideration to which a seller is contractually or legally entitled, but does not seek to collect through reasonable efforts. Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations removal of oil or gas—or the land area covered by that authorization, whichever the context requires. Lessee means any person to whom the United States issues an oil and gas lease, an assignee of all or a part of the record title interest, or any person to whom operating rights in a lease have been assigned. Location differential means an amount paid or received (whether in money or in barrels of oil) under an exchange agreement that results from differences in location between oil delivered in exchange and oil received in the exchange. A location differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell exchange agreement. Market center means a major point ONRR recognizes for oil sales, refining, or transshipment. Market centers generally are locations where ONRRapproved publications publish oil spot prices. Marketable condition means oil sufficiently free from impurities and otherwise in a condition a purchaser will accept under a sales contract typical for the field or area. Netting means reducing the reported sales value to account for transportation instead of reporting a transportation allowance as a separate entry on form ONRR–2014. NYMEX price means the average of the New York Mercantile Exchange (NYMEX) settlement prices for light sweet crude oil delivered at Cushing, Oklahoma, calculated as follows: (1) Sum the prices published for each day during the calendar month of production (excluding weekends and holidays) for oil to be delivered in the prompt month corresponding to each such day; and (2) Divide the sum by the number of days on which those prices are published (excluding weekends and holidays). Oil means a mixture of hydrocarbons that existed in the liquid phase in natural underground reservoirs, remains liquid at atmospheric pressure after passing through surface separating facilities, and is marketed or used as a liquid. Condensate recovered in lease separators or field facilities is oil. ONRR-approved publication means a publication ONRR approves for determining ANS spot prices or WTI differentials. Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity). Prompt month means the nearest month of delivery for which NYMEX futures prices are published during the trading month. Quality differential means an amount paid or received under an exchange agreement (whether in money or in barrels of oil) that results from differences in API gravity, sulfur content, viscosity, metals content, and other quality factors between oil delivered and oil received in the exchange. A quality differential may represent all or part of the difference between the price received for oil delivered and the price paid for oil received under a buy/sell agreement. Rocky Mountain Region means the States of Colorado, Montana, North Dakota, South Dakota, Utah, and Wyoming, except for those portions of the San Juan Basin and other oilproducing fields in the ‘‘Four Corners’’ area that lie within Colorado and Utah. Roll means an adjustment to the NYMEX price that is calculated as follows: Roll = .6667 × (P0 ¥ P1) + .3333 × (P0 ¥ P2), where: P0 = the average of the daily NYMEX settlement prices for deliveries during the prompt month that is the same as the month of production, as published for each day during the trading month for which the month of production is the prompt month; P1 = the average of the daily NYMEX settlement prices for deliveries during the month following the month of production, published for each day during the trading month for which the month of production is the prompt month; and P2 = the average of the daily NYMEX settlement prices for deliveries during the second month following the month of production, as published for each day during the trading month for which the month of production is the prompt month. Calculate the average of the daily NYMEX settlement prices using only the days on which such prices are published (excluding weekends and holidays). (1) Example 1. Prices in Out Months are Lower Going Forward: The month of production for which you must determine royalty value is March. March was the prompt month (for year 2003) from January 22 through February 20. April was the first month following the month of production, and May was the second month following the month of production. P0 therefore is the PO 00000 Frm 00023 Fmt 4701 Sfmt 4700 36955 average of the daily NYMEX settlement prices for deliveries during March published for each business day between January 22 and February 20. P1 is the average of the daily NYMEX settlement prices for deliveries during April published for each business day between January 22 and February 20. P2 is the average of the daily NYMEX settlement prices for deliveries during May published for each business day between January 22 and February 20. In this example, assume that P0 = $28.00 per bbl, P1 = $27.70 per bbl, and P2 = $27.10 per bbl. In this example (a declining market), Roll = .6667 × ($28.00 ¥ $27.70) + .3333 × ($28.00 ¥ $27.10) = $.20 + $.30 = $.50. You add this number to the NYMEX price. (2) Example 2. Prices in Out Months are Higher Going Forward: The month of production for which you must determine royalty value is July. July 2003 was the prompt month from May 21 through June 20. August was the first month following the month of production, and September was the second month following the month of production. P0 therefore is the average of the daily NYMEX settlement prices for deliveries during July published for each business day between May 21 and June 20. P1 is the average of the daily NYMEX settlement prices for deliveries during August published for each business day between May 21 and June 20. P2 is the average of the daily NYMEX settlement prices for deliveries during September published for each business day between May 21 and June 20. In this example, assume that P0 = $28.00 per bbl, P1 = $28.90 per bbl, and P2 = $29.50 per bbl. In this example (a rising market), Roll = .6667 × ($28.00¥$28.90) + .3333 × ($28.00 ¥ $29.50) = (¥$.60) + (¥$.50) = ¥$1.10. You add this negative number to the NYMEX price (effectively a subtraction from the NYMEX price). Sale means a contract between two persons where: (1) The seller unconditionally transfers title to the oil to the buyer and does not retain any related rights such as the right to buy back similar quantities of oil from the buyer elsewhere; (2) The buyer pays money or other consideration for the oil; and (3) The parties’ intent is for a sale of the oil to occur. Spot price means the price under a spot sales contract where: (1) A seller agrees to sell to a buyer a specified amount of oil at a specified price over a specified period of short duration; (2) No cancellation notice is required to terminate the sales agreement; and E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36956 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (3) There is no obligation or implied intent to continue to sell in subsequent periods. Tendering program means a producer’s offer of a portion of its crude oil produced from a field or area for competitive bidding, regardless of whether the production is offered or sold at or near the lease or unit or away from the lease or unit. Trading month means the period extending from the second business day before the 25th day of the second calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the second business day before the last business day preceding the 25th day of that month) through the third business day before the 25th day of the calendar month preceding the delivery month (or, if the 25th day of that month is a non-business day, the third business day before the last business day preceding the 25th day of that month), unless the NYMEX publishes a different definition or different dates on its official Web site, www.nymex.com, in which case the NYMEX definition will apply. Transportation allowance means a deduction in determining royalty value for the reasonable, actual costs of moving oil to a point of sale or delivery off the lease, unit area, or communitized area. The transportation allowance does not include gathering costs. WTI differential means the average of the daily mean differentials for location and quality between a grade of crude oil at a market center and West Texas Intermediate (WTI) crude oil at Cushing published for each day for which price publications perform surveys for deliveries during the production month, calculated over the number of days on which those differentials are published (excluding weekends and holidays). Calculate the daily mean differentials by averaging the daily high and low differentials for the month in the selected publication. Use only the days and corresponding differentials for which such differentials are published. (1) Example. Assume the production month was March 2003. Industry trade publications performed their price surveys and determined differentials during January 26 through February 25 for oil delivered in March. The WTI differential (for example, the West Texas Sour crude at Midland, Texas, spread versus WTI) applicable to valuing oil produced in the March 2003 production month would be determined using all the business days for which differentials were published during the period January 26 through February 25 excluding weekends and holidays (22 VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 days). To calculate the WTI differential, add together all of the daily mean differentials published for January 26 through February 25 and divide that sum by 22. (2) [Reserved] § 1206.102 How do I calculate royalty value for oil that I or my affiliate sell(s) under an arm’s-length contract? (a) The value of oil under this section is the gross proceeds accruing to the seller under the arm’s-length contract, less applicable allowances determined under § 1206.110 or § 1206.111. This value does not apply if you exercise an option to use a different value provided in paragraph (d)(1) or (d)(2)(i) of this section, or if one of the exceptions in paragraph (c) of this section applies. Use this paragraph (a) to value oil that: (1) You sell under an arm’s-length sales contract; or (2) You sell or transfer to your affiliate or another person under a non-arm’slength contract and that affiliate or person, or another affiliate of either of them, then sells the oil under an arm’slength contract, unless you exercise the option provided in paragraph (d)(2)(i) of this section. (b) If you have multiple arm’s-length contracts to sell oil produced from a lease that is valued under paragraph (a) of this section, the value of the oil is the volume-weighted average of the values established under this section for each contract for the sale of oil produced from that lease. (c) This paragraph contains exceptions to the valuation rule in paragraph (a) of this section. Apply these exceptions on an individual contract basis. (1) In conducting reviews and audits, if ONRR determines that any arm’slength sales contract does not reflect the total consideration actually transferred either directly or indirectly from the buyer to the seller, ONRR may require that you value the oil sold under that contract either under § 1206.103 or at the total consideration received. (2) You must value the oil under § 1206.103 if ONRR determines that the value under paragraph (a) of this section does not reflect the reasonable value of the production due to either: (i) Misconduct by or between the parties to the arm’s-length contract; or (ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor. (A) ONRR will not use this provision to simply substitute its judgment of the market value of the oil for the proceeds received by the seller under an arm’slength sales contract. (B) The fact that the price received by the seller under an arm’s-length contract PO 00000 Frm 00024 Fmt 4701 Sfmt 4700 is less than other measures of market price, such as index prices, is insufficient to establish breach of the duty to market unless ONRR finds additional evidence that the seller acted unreasonably or in bad faith in the sale of oil from the lease. (d)(1) If you enter into an arm’s-length exchange agreement, or multiple sequential arm’s-length exchange agreements, and following the exchange(s) you or your affiliate sell(s) the oil received in the exchange(s) under an arm’s-length contract, then you may use either § 1206.102(a) or § 1206.103 to value your production for royalty purposes. (i) If you use § 1206.102(a), your gross proceeds are the gross proceeds under your or your affiliate’s arm’s-length sales contract after the exchange(s) occur(s). You must adjust your gross proceeds for any location or quality differential, or other adjustments, you received or paid under the arm’s-length exchange agreement(s). If ONRR determines that any arm’s-length exchange agreement does not reflect reasonable location or quality differentials, ONRR may require you to value the oil under § 1206.103. You may not otherwise use the price or differential specified in an arm’s-length exchange agreement to value your production. (ii) When you elect under § 1206.102(d)(1) to use § 1206.102(a) or § 1206.103, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) sold under arm’s-length contracts following arm’s-length exchange agreements. You may not change your election more often than once every 2 years. (2)(i) If you sell or transfer your oil production to your affiliate and that affiliate or another affiliate then sells the oil under an arm’s-length contract, you may use either § 1206.102(a) or § 1206.103 to value your production for royalty purposes. (ii) When you elect under § 1206.102(d)(2)(i) to use § 1206.102(a) or § 1206.103, you must make the same election for all of your production from the same unit, communitization agreement, or lease (if the lease is not part of a unit or communitization agreement) that your affiliates resell at arm’s length. You may not change your election more often than once every 2 years. (e) If you value oil under paragraph (a) of this section: (1) ONRR may require you to certify that your or your affiliate’s arm’s-length E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations contract provisions include all of the consideration the buyer must pay, either directly or indirectly, for the oil. (2) You must base value on the highest price the seller can receive through legally enforceable claims under the contract. (i) If the seller fails to take proper or timely action to receive prices or benefits it is entitled to, you must pay royalty at a value based upon that obtainable price or benefit. But you will owe no additional royalties unless or until the seller receives monies or consideration resulting from the price increase or additional benefits, if: (A) The seller makes timely application for a price increase or benefit allowed under the contract; (B) The purchaser refuses to comply; and (C) The seller takes reasonable documented measures to force purchaser compliance. (ii) Paragraph (e)(2)(i) of this section will not permit you to avoid your royalty payment obligation where a purchaser fails to pay, pays only in part, or pays late. Any contract revisions or amendments that reduce prices or benefits to which the seller is entitled must be in writing and signed by all parties to the arm’s-length contract. mstockstill on DSK30JT082PROD with RULES3 § 1206.103 How do I value oil that is not sold under an arm’s-length contract? This section explains how to value oil that you may not value under § 1206.102 or that you elect under § 1206.102(d) to value under this section. First determine whether paragraph (a), (b), or (c) of this section applies to production from your lease, or whether you may apply paragraph (d) or (e) with ONRR approval. (a) Production from leases in California or Alaska. Value is the average of the daily mean ANS spot prices published in any ONRR-approved publication during the trading month most concurrent with the production month. (For example, if the production month is June, compute the average of the daily mean prices using the daily ANS spot prices published in the ONRR-approved publication for all the business days in June.) (1) To calculate the daily mean spot price, average the daily high and low prices for the month in the selected publication. (2) Use only the days and corresponding spot prices for which such prices are published. (3) You must adjust the value for applicable location and quality differentials, and you may adjust it for transportation costs, under § 1206.112. (4) After you select an ONRRapproved publication, you may not VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 select a different publication more often than once every 2 years, unless the publication you use is no longer published or ONRR revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period. (b) Production from leases in the Rocky Mountain Region. This paragraph provides methods and options for valuing your production under different factual situations. You must consistently apply paragraph (b)(1), (2), or (3) of this section to value all of your production from the same unit, communitization agreement, or lease (if the lease or a portion of the lease is not part of a unit or communitization agreement) that you cannot value under § 1206.102 or that you elect under § 1206.102(d) to value under this section. (1) If you have an ONRR-approved tendering program, you must value oil produced from leases in the area the tendering program covers at the highest winning bid price for tendered volumes. (i) The minimum requirements for ONRR to approve your tendering program are: (A) You must offer and sell at least 30 percent of your or your affiliates’ production from both Federal and nonFederal leases in the area under your tendering program; and (B) You must receive at least three bids for the tendered volumes from bidders who do not have their own tendering programs that cover some or all of the same area. (ii) If you do not have an ONRRapproved tendering program, you may elect to value your oil under either paragraph (b)(2) or (3) of this section. After you select either paragraph (b)(2) or (3) of this section, you may not change to the other method more often than once every 2 years, unless the method you have been using is no longer applicable and you must apply the other paragraph. If you change methods, you must begin a new 2-year period. (2) Value is the volume-weighted average of the gross proceeds accruing to the seller under your or your affiliates’ arm’s-length contracts for the purchase or sale of production from the field or area during the production month. (i) The total volume purchased or sold under those contracts must exceed 50 percent of your and your affiliates’ production from both Federal and nonFederal leases in the same field or area during that month. (ii) Before calculating the volumeweighted average, you must normalize the quality of the oil in your or your PO 00000 Frm 00025 Fmt 4701 Sfmt 4700 36957 affiliates’ arm’s-length purchases or sales to the same gravity as that of the oil produced from the lease. (3) Value is the NYMEX price (without the roll), adjusted for applicable location and quality differentials and transportation costs under § 1206.112. (4) If you demonstrate to ONRR’s satisfaction that paragraphs (b)(1) through (b)(3) of this section result in an unreasonable value for your production as a result of circumstances regarding that production, the ONRR Director may establish an alternative valuation method. (c) Production from leases not located in California, Alaska, or the Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll, adjusted for applicable location and quality differentials and transportation costs under § 1206.112. (2) If the ONRR Director determines that use of the roll no longer reflects prevailing industry practice in crude oil sales contracts or that) the most common formula used by industry to calculate the roll changes, ONRR may terminate or modify use of the roll under paragraph (c)(1) of this section at the end of each 2-year period following July 6, 2004, through notice published in the Federal Register not later than 60 days before the end of the 2-year period. ONRR will explain the rationale for terminating or modifying the use of the roll in this notice. (d) Unreasonable value. If ONRR determines that the NYMEX price or ANS spot price does not represent a reasonable royalty value in any particular case, ONRR may establish reasonable royalty value based on other relevant matters. (e) Production delivered to your refinery and the NYMEX price or ANS spot price is an unreasonable value. (1) Instead of valuing your production under paragraph (a), (b), or (c) of this section, you may apply to the ONRR Director to establish a value representing the market at the refinery if: (i) You transport your oil directly to your or your affiliate’s refinery, or exchange your oil for oil delivered to your or your affiliate’s refinery; and (ii) You must value your oil under this section at the NYMEX price or ANS spot price; and (iii) You believe that use of the NYMEX price or ANS spot price results in an unreasonable royalty value. (2) You must provide adequate documentation and evidence demonstrating the market value at the refinery. That evidence may include, but is not limited to: E:\FR\FM\07AUR3.SGM 07AUR3 36958 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (i) Costs of acquiring other crude oil at or for the refinery; (ii) How adjustments for quality, location, and transportation were factored into the price paid for other oil; (iii) Volumes acquired for and refined at the refinery; and (iv) Any other appropriate evidence or documentation that ONRR requires. (3) If the ONRR Director establishes a value representing market value at the refinery, you may not take an allowance against that value under § 1206.112(b) unless it is included in the Director’s approval. § 1206.104 What publications are acceptable to ONRR? (a) ONRR periodically will publish in the Federal Register a list of acceptable publications for the NYMEX price and ANS spot price based on certain criteria, including, but not limited to: (1) Publications buyers and sellers frequently use; (2) Publications frequently mentioned in purchase or sales contracts; (3) Publications that use adequate survey techniques, including development of estimates based on daily surveys of buyers and sellers of crude oil, and, for ANS spot prices, buyers and sellers of ANS crude oil; and (4) Publications independent from ONRR, other lessors, and lessees. (b) Any publication may petition ONRR to be added to the list of acceptable publications. (c) ONRR will specify the tables you must use in the acceptable publications. (d) ONRR may revoke its approval of a particular publication if it determines that the prices or differentials published in the publication do not accurately represent NYMEX prices or differentials or ANS spot market prices or differentials. mstockstill on DSK30JT082PROD with RULES3 § 1206.105 What records must I keep to support my calculations of value under this subpart? If you determine the value of your oil under this subpart, you must retain all data relevant to the determination of royalty value. (a) You must be able to show: (1) How you calculated the value you reported, including all adjustments for location, quality, and transportation, and (2) How you complied with these rules. (b) Recordkeeping requirements are found at part 1207 of this chapter. (c) ONRR may review and audit your data, and ONRR will direct you to use a different value if it determines that the reported value is inconsistent with the requirements of this subpart. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 § 1206.106 What are my responsibilities to place production into marketable condition and to market production? You must place oil in marketable condition and market the oil for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. If you use gross proceeds under an arm’s-length contract in determining value, you must increase those gross proceeds to the extent that the purchaser, or any other person, provides certain services that the seller normally would be responsible to perform to place the oil in marketable condition or to market the oil. § 1206.107 How do I request a value determination? (a) You may request a value determination from ONRR regarding any Federal lease oil production. Your request must: (1) Be in writing; (2) Identify specifically all leases involved, the record title or operating rights owners of those leases, and the designees for those leases; (3) Completely explain all relevant facts. You must inform ONRR of any changes to relevant facts that occur before we respond to your request; (4) Include copies of all relevant documents; (5) Provide your analysis of the issue(s), including citations to all relevant precedents (including adverse precedents); and (6) Suggest your proposed valuation method. (b) ONRR will reply to requests expeditiously. ONRR may either: (1) Issue a value determination signed by the Assistant Secretary, Policy, Management and Budget; or (2) Issue a value determination by ONRR; or (3) Inform you in writing that ONRR will not provide a value determination. Situations in which ONRR typically will not provide any value determination include, but are not limited to: (i) Requests for guidance on hypothetical situations; and (ii) Matters that are the subject of pending litigation or administrative appeals. (c)(1) A value determination signed by the Assistant Secretary, Policy, Management and Budget, is binding on both you and ONRR until the Assistant Secretary modifies or rescinds it. (2) After the Assistant Secretary issues a value determination, you must make any adjustments in royalty payments that follow from the determination and, if you owe additional royalties, pay late payment interest under § 1218.54 of this chapter. PO 00000 Frm 00026 Fmt 4701 Sfmt 4700 (3) A value determination signed by the Assistant Secretary is the final action of the Department and is subject to judicial review under 5 U.S.C. 701– 706. (d) A value determination issued by ONRR is binding on ONRR and delegated States with respect to the specific situation addressed in the determination unless the ONRR (for ONRR-issued value determinations) or the Assistant Secretary modifies or rescinds it. (1) A value determination by ONRR is not an appealable decision or order under 30 CFR part 1290. (2) If you receive an order requiring you to pay royalty on the same basis as the value determination, you may appeal that order under 30 CFR part 1290. (e) In making a value determination, ONRR or the Assistant Secretary may use any of the applicable valuation criteria in this subpart. (f) A change in an applicable statute or regulation on which any value determination is based takes precedence over the value determination, regardless of whether the ONRR or the Assistant Secretary modifies or rescinds the value determination. (g) The ONRR or the Assistant Secretary generally will not retroactively modify or rescind a value determination issued under paragraph (d) of this section, unless: (1) There was a misstatement or omission of material facts; or (2) The facts subsequently developed are materially different from the facts on which the guidance was based. (h) ONRR may make requests and replies under this section available to the public, subject to the confidentiality requirements under § 1206.108. § 1206.108 I provide? Does ONRR protect information Certain information you submit to ONRR regarding valuation of oil, including transportation allowances, may be exempt from disclosure. To the extent applicable laws and regulations permit, ONRR will keep confidential any data you submit that is privileged, confidential, or otherwise exempt from disclosure. All requests for information must be submitted under the Freedom of Information Act regulations of the Department of the Interior at 43 CFR part 2. § 1206.109 When may I take a transportation allowance in determining value? (a) Transportation allowances permitted when value is based on gross proceeds. ONRR will allow a deduction E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations for the reasonable, actual costs to transport oil from the lease to the point off the lease under § 1206.110 or § 1206.111, as applicable. This paragraph applies when: (1) You value oil under § 1206.102 based on gross proceeds from a sale at a point off the lease, unit, or communitized area where the oil is produced, and (2) The movement to the sales point is not gathering. (b) Transportation allowances and other adjustments that apply when value is based on NYMEX prices or ANS spot prices. If you value oil using NYMEX prices or ANS spot prices under § 1206.103, ONRR will allow an adjustment for certain location and quality differentials and certain costs associated with transporting oil as provided under § 1206.112. (c) Limits on transportation allowances. (1) Except as provided in paragraph (c)(2) of this section, your transportation allowance may not exceed 50 percent of the value of the oil as determined under § 1206.102 or § 1206.103 of this subpart. You may not use transportation costs incurred to move a particular volume of production to reduce royalties owed on production for which those costs were not incurred. (2) You may ask ONRR to approve a transportation allowance in excess of the limitation in paragraph (c)(1) of this section. You must demonstrate that the transportation costs incurred were reasonable, actual, and necessary. Your application for exception (using form ONRR–4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for ONRR to make a determination. You may never reduce the royalty value of any production to zero. (d) Allocation of transportation costs. You must allocate transportation costs among all products produced and transported as provided in §§ 1206.110 and 1206.111. You must express transportation allowances for oil as dollars per barrel. (e) Liability for additional payments. If ONRR determines that you took an excessive transportation allowance, then you must pay any additional royalties due, plus interest under § 1218.54 of this chapter. You also could be entitled to a credit with interest under applicable rules if you understated your transportation allowance. If you take a deduction for transportation on form ONRR–2014 by improperly netting the allowance against the sales value of the oil instead of reporting the allowance as a separate entry, ONRR may assess you an amount under § 1206.116. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 § 1206.110 How do I determine a transportation allowance under an arm’slength transportation contract? (a) If you or your affiliate incur transportation costs under an arm’slength transportation contract, you may claim a transportation allowance for the reasonable, actual costs incurred as more fully explained in paragraph (b) of this section, except as provided in paragraphs (a)(1) and (2) of this section and subject to the limitation in § 1206.109(c). You must be able to demonstrate that your or your affiliate’s contract is at arm’s length. You do not need ONRR approval before reporting a transportation allowance for costs incurred under an arm’s-length transportation contract. (1) If ONRR determines that the contract reflects more than the consideration actually transferred either directly or indirectly from you or your affiliate to the transporter for the transportation, ONRR may require that you calculate the transportation allowance under § 1206.111. (2) You must calculate the transportation allowance under § 1206.111 if ONRR determines that the consideration paid under an arm’slength transportation contract does not reflect the reasonable value of the transportation due to either: (i) Misconduct by or between the parties to the arm’s-length contract; or (ii) Breach of your duty to market the oil for the mutual benefit of yourself and the lessor. (A) ONRR will not use this provision to simply substitute its judgment of the reasonable oil transportation costs incurred by you or your affiliate under an arm’s-length transportation contract. (B) The fact that the cost you or your affiliate incur in an arm’s-length transaction is higher than other measures of transportation costs, such as rates paid by others in the field or area, is insufficient to establish breach of the duty to market unless ONRR finds additional evidence that you or your affiliate acted unreasonably or in bad faith in transporting oil from the lease. (b) You may deduct any of the following actual costs you (including your affiliates) incur for transporting oil. You may not use as a deduction any cost that duplicates all or part of any other cost that you use under this paragraph. (1) The amount that you pay under your arm’s-length transportation contract or tariff. (2) Fees paid (either in volume or in value) for actual or theoretical line losses. (3) Fees paid for administration of a quality bank. PO 00000 Frm 00027 Fmt 4701 Sfmt 4700 36959 (4) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows: (i) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the pipeline by the value of that volume for the current month calculated under § 1206.102 or § 1206.103, as applicable; and (ii) Multiply the value calculated under paragraph (b)(4)(i) of this section by the monthly rate of return, calculated by dividing the rate of return specified in § 1206.111(i)(2) by 12. (5) Fees paid to a terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance. (6) Fees paid for short-term storage (30 days or less) incidental to transportation as required by a transporter. (7) Fees paid to pump oil to another carrier’s system or vehicles as required under a tariff. (8) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when you do not sell the oil at the hub. These fees do not include title transfer fees. (9) Payments for a volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation. (10) Costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to maintain. (c) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to the following: (1) Fees paid for long-term storage (more than 30 days). (2) Administrative, handling, and accounting fees associated with terminalling. (3) Title and terminal transfer fees. (4) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title transfer fees. (5) Fees paid to brokers. (6) Fees paid to a scheduling service provider. (7) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production. (8) Gauging fees. (d) If your arm’s-length transportation contract includes more than one liquid E:\FR\FM\07AUR3.SGM 07AUR3 36960 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations mstockstill on DSK30JT082PROD with RULES3 product, and the transportation costs attributable to each product cannot be determined from the contract, then you must allocate the total transportation costs to each of the liquid products transported. (1) Your allocation must use the same proportion as the ratio of the volume of each product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value). (2) You may not claim an allowance for the costs of transporting lease production that is not royalty-bearing. (3) You may propose to ONRR a cost allocation method on the basis of the values of the products transported. ONRR will approve the method unless it is not consistent with the purposes of the regulations in this subpart. (e) If your arm’s-length transportation contract includes both gaseous and liquid products, and the transportation costs attributable to each product cannot be determined from the contract, then you must propose an allocation procedure to ONRR. (1) You may use your proposed procedure to calculate a transportation allowance until ONRR accepts or rejects your cost allocation. If ONRR rejects your cost allocation, you must amend your form ONRR–2014 for the months that you used the rejected method and pay any additional royalty and interest due. (2) You must submit your initial proposal, including all available data, within 3 months after first claiming the allocated deductions on form ONRR– 2014. (f) If your payments for transportation under an arm’s-length contract are not on a dollar-per-unit basis, you must convert whatever consideration is paid to a dollar-value equivalent. (g) If your arm’s-length sales contract includes a provision reducing the contract price by a transportation factor, do not separately report the transportation factor as a transportation allowance on form ONRR–2014. (1) You may use the transportation factor in determining your gross proceeds for the sale of the product. (2) You must obtain ONRR approval before claiming a transportation factor in excess of 50 percent of the base price of the product. § 1206.111 How do I determine a transportation allowance if I do not have an arm’s-length transportation contract or arm’s-length tariff? (a) This section applies if you or your affiliate do not have an arm’s-length transportation contract, including situations where you or your affiliate VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 provide your own transportation services. Calculate your transportation allowance based on your or your affiliate’s reasonable, actual costs for transportation during the reporting period using the procedures prescribed in this section. (b) Your or your affiliate’s actual costs include the following: (1) Operating and maintenance expenses under paragraphs (d) and (e) of this section; (2) Overhead under paragraph (f) of this section; (3) Depreciation under paragraphs (g) and (h) of this section; (4) A return on undepreciated capital investment under paragraph (i) of this section; and (5) Once the transportation system has been depreciated below ten percent of total capital investment, a return on ten percent of total capital investment under paragraph (j) of this section. (6) To the extent not included in costs identified in paragraphs (d) through (j) of this section, you may also deduct the following actual costs. You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this section: (i) Volumetric adjustments for actual (not theoretical) line losses. (ii) The cost of carrying on your books as inventory a volume of oil that the pipeline operator requires you as a shipper to maintain, and that you do maintain, in the line as line fill. You must calculate this cost as follows: (A) Multiply the volume that the pipeline requires you to maintain, and that you do maintain, in the pipeline by the value of that volume for the current month calculated under § 1206.102 or § 1206.103, as applicable; and (B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of this section by the monthly rate of return, calculated by dividing the rate of return specified in § 1206.111(i)(2) by 12. (iii) Fees paid to a non-affiliated terminal operator for loading and unloading of crude oil into or from a vessel, vehicle, pipeline, or other conveyance. (iv) Transfer fees paid to a hub operator associated with physical movement of crude oil through the hub when you do not sell the oil at the hub. These fees do not include title transfer fees. (v) A volumetric deduction to cover shrinkage when high-gravity petroleum (generally in excess of 51 degrees API) is mixed with lower-gravity crude oil for transportation. (vi) Fees paid to a non-affiliated quality bank administrator for administration of a quality bank. PO 00000 Frm 00028 Fmt 4701 Sfmt 4700 (7) You may not deduct any costs that are not actual costs of transporting oil, including but not limited to the following: (i) Fees paid for long-term storage (more than 30 days). (ii) Administrative, handling, and accounting fees associated with terminalling. (iii) Title and terminal transfer fees. (iv) Fees paid to track and match receipts and deliveries at a market center or to avoid paying title transfer fees. (v) Fees paid to brokers. (vi) Fees paid to a scheduling service provider. (vii) Internal costs, including salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production. (viii) Theoretical line losses. (ix) Gauging fees. (c) Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system. (d) Allowable operating expenses include: (1) Operations supervision and engineering; (2) Operations labor; (3) Fuel; (4) Utilities; (5) Materials; (6) Ad valorem property taxes; (7) Rent; (8) Supplies; and (9) Any other directly allocable and attributable operating expense which you can document. (e) Allowable maintenance expenses include: (1) Maintenance of the transportation system; (2) Maintenance of equipment; (3) Maintenance labor; and (4) Other directly allocable and attributable maintenance expenses which you can document. (f) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses. (g) To compute depreciation, you may elect to use either a straight-line depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit-of-production method. After you make an election, you may not change methods without E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations ONRR approval. You may not depreciate equipment below a reasonable salvage value. (h) This paragraph describes the basis for your depreciation schedule. (1) If you or your affiliate own a transportation system on June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs for production after June 1, 2000, on your total capital investment in the system (including your original purchase price or construction cost and subsequent reinvestment). (2) If you or your affiliate purchased the transportation system at arm’s length before June 1, 2000, you must incorporate depreciation on the schedule based on your purchase price (and subsequent reinvestment) into your transportation allowance calculations for production after June 1, 2000, beginning at the point on the depreciation schedule corresponding to that date. You must prorate your depreciation for calendar year 2000 by claiming part-year depreciation for the period from June 1, 2000 until December 31, 2000. You may not adjust your transportation costs for production before June 1, 2000, using the depreciation schedule based on your purchase price. (3) If you are the original owner of the transportation system on June 1, 2000, or if you purchased your transportation system before March 1, 1988, you must continue to use your existing depreciation schedule in calculating actual transportation costs for production in periods after June 1, 2000. (4) If you or your affiliate purchase a transportation system at arm’s length from the original owner after June 1, 2000, you must base your depreciation schedule used in calculating actual transportation costs on your total capital investment in the system (including your original purchase price and subsequent reinvestment). You must prorate your depreciation for the year in which you or your affiliate purchased the system to reflect the portion of that year for which you or your affiliate own the system. (5) If you or your affiliate purchase a transportation system at arm’s length after June 1, 2000, from anyone other than the original owner, you must assume the depreciation schedule of the person from whom you bought the system. Include in the depreciation schedule any subsequent reinvestment. (i)(1) To calculate a return on undepreciated capital investment, multiply the remaining undepreciated capital balance as of the beginning of the period for which you are calculating VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 the transportation allowance by the rate of return provided in paragraph (i)(2) of this section. (2) The rate of return is 1.3 times the industrial bond yield index for Standard & Poor’s BBB bond rating. Use the monthly average rate published in ‘‘Standard & Poor’s Bond Guide’’ for the first month of the reporting period for which the allowance applies. Calculate the rate at the beginning of each subsequent transportation allowance reporting period. (j)(1) After a transportation system has been depreciated at or below a value equal to ten percent of your total capital investment, you may continue to include in the allowance calculation a cost equal to ten percent of your total capital investment in the transportation system multiplied by a rate of return under paragraph (i)(2) of this section. (2) You may apply this paragraph to a transportation system that before June 1, 2000, was depreciated at or below a value equal to ten percent of your total capital investment. (k) Calculate the deduction for transportation costs based on your or your affiliate’s cost of transporting each product through each individual transportation system. Where more than one liquid product is transported, allocate costs consistently and equitably to each of the liquid products transported. Your allocation must use the same proportion as the ratio of the volume of each liquid product (excluding waste products with no value) to the volume of all liquid products (excluding waste products with no value). (1) You may not take an allowance for transporting lease production that is not royalty-bearing. (2) You may propose to ONRR a cost allocation method on the basis of the values of the products transported. ONRR will approve the method if it is consistent with the purposes of the regulations in this subpart. (l)(1) Where you transport both gaseous and liquid products through the same transportation system, you must propose a cost allocation procedure to ONRR. (2) You may use your proposed procedure to calculate a transportation allowance until ONRR accepts or rejects your cost allocation. If ONRR rejects your cost allocation, you must amend your form ONRR–2014 for the months that you used the rejected method and pay any additional royalty and interest due. (3) You must submit your initial proposal, including all available data, within 3 months after first claiming the PO 00000 Frm 00029 Fmt 4701 Sfmt 4700 36961 allocated deductions on form ONRR– 2014. § 1206.112 What adjustments and transportation allowances apply when I value oil production from my lease using NYMEX prices or ANS spot prices? This section applies when you use NYMEX prices or ANS spot prices to calculate the value of production under § 1206.103. As specified in this section, adjust the NYMEX price to reflect the difference in value between your lease and Cushing, Oklahoma, or adjust the ANS spot price to reflect the difference in value between your lease and the appropriate ONRR-recognized market center at which the ANS spot price is published (for example, Long Beach, California, or San Francisco, California). Paragraph (a) of this section explains how you adjust the value between the lease and the market center, and paragraph (b) of this section explains how you adjust the value between the market center and Cushing when you use NYMEX prices. Paragraph (c) of this section explains how adjustments may be made for quality differentials that are not accounted for through exchange agreements. Paragraph (d) of this section gives some examples. References in this section to ‘‘you’’ include your affiliates as applicable. (a) To adjust the value between the lease and the market center: (1)(i) For oil that you exchange at arm’s length between your lease and the market center (or between any intermediate points between those locations), you must calculate a lease-tomarket center differential by the applicable location and quality differentials derived from your arm’slength exchange agreement applicable to production during the production month. (ii) For oil that you exchange between your lease and the market center (or between any intermediate points between those locations) under an exchange agreement that is not at arm’s length, you must obtain approval from ONRR for a location and quality differential. Until you obtain such approval, you may use the location and quality differential derived from that exchange agreement applicable to production during the production month. If ONRR prescribes a different differential, you must apply ONRR’s differential to all periods for which you used your proposed differential. You must pay any additional royalties owed resulting from using ONRR’s differential plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h). E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36962 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (2) For oil that you transport between your lease and the market center (or between any intermediate points between those locations), you may take an allowance for the cost of transporting that oil between the relevant points as determined under § 1206.110 or § 1206.111, as applicable. (3) If you transport or exchange at arm’s length (or both transport and exchange) at least 20 percent, but not all, of your oil produced from the lease to a market center, determine the adjustment between the lease and the market center for the oil that is not transported or exchanged (or both transported and exchanged) to or through a market center as follows: (i) Determine the volume-weighted average of the lease-to-market center adjustment calculated under paragraphs (a)(1) and (2) of this section for the oil that you do transport or exchange (or both transport and exchange) from your lease to a market center. (ii) Use that volume-weighted average lease-to-market center adjustment as the adjustment for the oil that you do not transport or exchange (or both transport and exchange) from your lease to a market center. (4) If you transport or exchange (or both transport and exchange) less than 20 percent of the crude oil produced from your lease between the lease and a market center, you must propose to ONRR an adjustment between the lease and the market center for the portion of the oil that you do not transport or exchange (or both transport and exchange) to a market center. Until you obtain such approval, you may use your proposed adjustment. If ONRR prescribes a different adjustment, you must apply ONRR’s adjustment to all periods for which you used your proposed adjustment. You must pay any additional royalties owed resulting from using ONRR’s adjustment plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h). (5) You may not both take a transportation allowance and use a location and quality adjustment or exchange differential for the same oil between the same points. (b) For oil that you value using NYMEX prices, adjust the value between the market center and Cushing, Oklahoma, as follows: (1) If you have arm’s-length exchange agreements between the market center and Cushing under which you exchange to Cushing at least 20 percent of all the oil you own at the market center during the production month, you must use the volume-weighted average of the location VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 and quality differentials from those agreements as the adjustment between the market center and Cushing for all the oil that you produce from the leases during that production month for which that market center is used. (2) If paragraph (b)(1) of this section does not apply, you must use the WTI differential published in an ONRRapproved publication for the market center nearest your lease, for crude oil most similar in quality to your production, as the adjustment between the market center and Cushing. (For example, for light sweet crude oil produced offshore of Louisiana, use the WTI differential for Light Louisiana Sweet crude oil at St. James, Louisiana.) After you select an ONRR-approved publication, you may not select a different publication more often than once every 2 years, unless the publication you use is no longer published or ONRR revokes its approval of the publication. If you are required to change publications, you must begin a new 2-year period. (3) If neither paragraph (b)(1) nor (b)(2) of this section applies, you may propose an alternative differential to ONRR. Until you obtain such approval, you may use your proposed differential. If ONRR prescribes a different differential, you must apply ONRR’s differential to all periods for which you used your proposed differential. You must pay any additional royalties owed resulting from using ONRR’s differential plus late payment interest from the original royalty due date, or you may report a credit for any overpaid royalties plus interest under 30 U.S.C. 1721(h). (c)(1) If you adjust for location and quality differentials or for transportation costs under paragraphs (a) and (b) of this section, also adjust the NYMEX price or ANS spot price for quality based on premiums or penalties determined by pipeline quality bank specifications at intermediate commingling points or at the market center if those points are downstream of the royalty measurement point approved by BSEE or BLM, as applicable. Make this adjustment only if and to the extent that such adjustments were not already included in the location and quality differentials determined from your arm’s-length exchange agreements. (2) If the quality of your oil as adjusted is still different from the quality of the representative crude oil at the market center after making the quality adjustments described in paragraphs (a), (b), and (c)(1) of this section, you may make further gravity adjustments using posted price gravity tables. If quality bank adjustments do PO 00000 Frm 00030 Fmt 4701 Sfmt 4700 not incorporate or provide for adjustments for sulfur content, you may make sulfur adjustments, based on the quality of the representative crude oil at the market center, of 5.0 cents per onetenth percent difference in sulfur content, unless ONRR approves a higher adjustment. (d) The examples in this paragraph illustrate how to apply the requirement of this section. (1) Example. Assume that a Federal lessee produces crude oil from a lease near Artesia, New Mexico. Further, assume that the lessee transports the oil to Roswell, New Mexico, and then exchanges the oil to Midland, Texas. Assume the lessee refines the oil received in exchange at Midland. Assume that the NYMEX price is $30.00/bbl, adjusted for the roll; that the WTI differential (Cushing to Midland) is ¥$.10/bbl; that the lessee’s exchange agreement between Roswell and Midland results in a location and quality differential of ¥$.08/bbl; and that the lessee’s actual cost of transporting the oil from Artesia to Roswell is $.40/bbl. In this example, the royalty value of the oil is $30.00¥$.10¥$.08—$.40 = $29.42/bbl. (2) Example. Assume the same facts as in the example in paragraph (d)(1) of this section, except that the lessee transports and exchanges to Midland 40 percent of the production from the lease near Artesia, and transports the remaining 60 percent directly to its own refinery in Ohio. In this example, the 40 percent of the production would be valued at $29.42/bbl, as explained in the previous example. In this example, the other 60 percent also would be valued at $29.42/bbl. (3) Example. Assume that a Federal lessee produces crude oil from a lease near Bakersfield, California. Further, assume that the lessee transports the oil to Hynes Station, and then exchanges the oil to Cushing which it further exchanges with oil it refines. Assume that the ANS spot price is $20.00/bbl, and that the lessee’s actual cost of transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The lessee must request approval from ONRR for a location and quality adjustment between Hynes Station and Long Beach. For example, the lessee likely would propose using the tariff on Line 63 from Hynes Station to Long Beach as the adjustment between those points. Assume that adjustment to be $.72, including the sulfur and gravity bank adjustments, and that ONRR approves the lessee’s request. In this example, the preliminary (because the location and quality adjustment is subject to ONRR review) royalty value of the oil is E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations $20.00¥$.72¥$.28 = $19.00/bbl. The fact that oil was exchanged to Cushing does not change use of ANS spot prices for royalty valuation. § 1206.113 centers? How will ONRR identify market ONRR periodically will publish in the Federal Register a list of market centers. ONRR will monitor market activity and, if necessary, add to or modify the list of market centers and will publish such modifications in the Federal Register. ONRR will consider the following factors and conditions in specifying market centers: (a) Points where ONRR-approved publications publish prices useful for index purposes; (b) Markets served; (c) Input from industry and others knowledgeable in crude oil marketing and transportation; (d) Simplification; and (e) Other relevant matters. § 1206.114 What are my reporting requirements under an arm’s-length transportation contract? You or your affiliate must use a separate entry on form ONRR–2014 to notify ONRR of an allowance based on transportation costs you or your affiliate incur. ONRR may require you or your affiliate to submit arm’s-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 1207 of this chapter. mstockstill on DSK30JT082PROD with RULES3 § 1206.115 What are my reporting requirements under a non-arm’s-length transportation arrangement? (a) You or your affiliate must use a separate entry on form ONRR–2014 to notify ONRR of an allowance based on transportation costs you or your affiliate incur. (b) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable oil transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems. Section 1206.117 will apply when you amend your report based on your actual costs. (c) ONRR may require you or your affiliate to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 1207 of this chapter. § 1206.116 What interest applies if I improperly report a transportation allowance? (a) If you or your affiliate deducts a transportation allowance on form VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 ONRR–2014 that exceeds 50 percent of the value of the oil transported without obtaining ONRR’s prior approval under § 1206.109, you must pay interest on the excess allowance amount taken from the date that amount is taken to the date you or your affiliate files an exception request that ONRR approves. If you do not file an exception request, or if ONRR does not approve your request, you must pay interest on the excess allowance amount taken from the date that amount is taken until the date you pay the additional royalties owed. (b) If you or your affiliate takes a deduction for transportation on form ONRR–2014 by improperly netting an allowance against the oil instead of reporting the allowance as a separate entry, ONRR may assess a civil penalty under 30 CFR part 1241. § 1206.117 What reporting adjustments must I make for transportation allowances? (a) If your or your affiliate’s actual transportation allowance is less than the amount you claimed on form ONRR– 2014 for each month during the allowance reporting period, you must pay additional royalties plus interest computed under § 1218.54 of this chapter from the date you took the deduction to the date you repay the difference. (b) If the actual transportation allowance is greater than the amount you claimed on form ONRR–2014 for any month during the allowance form reporting period, you are entitled to a credit plus interest under applicable rules. § 1206.119 How are royalty quantity and quality determined? (a) Compute royalties based on the quantity and quality of oil as measured at the point of settlement approved by BLM for onshore leases or BSEE for offshore leases. (b) If the value of oil determined under this subpart is based upon a quantity or quality different from the quantity or quality at the point of royalty settlement approved by the BLM for onshore leases or BSEE for offshore leases, adjust the value for those differences in quantity or quality. (c) Any actual loss that you may incur before the royalty settlement metering or measurement point is not subject to royalty if BLM or BSEE, as appropriate, determines that the loss is unavoidable. (d) Except as provided in paragraph (b) of this section, royalties are due on 100 percent of the volume measured at the approved point of royalty settlement. You may not claim a reduction in that measured volume for actual losses beyond the approved point PO 00000 Frm 00031 Fmt 4701 Sfmt 4700 36963 of royalty settlement or for theoretical losses that are claimed to have taken place either before or after the approved point of royalty settlement. § 1206.120 How are operating allowances determined? BOEM may use an operating allowance for the purpose of computing payment obligations when specified in the notice of sale and the lease. BOEM will specify the allowance amount or formula in the notice of sale and in the lease agreement. ■ 7. Revise subpart D to read as follows: Subpart D—Federal Gas Sec. 1206.150 Purpose and scope. 1206.151 Definitions. 1206.152 Valuation standards— unprocessed gas. 1206.153 Valuation standards—processed gas. 1206.154 Determination of quantities and qualities for computing royalties. 1206.155 Accounting for comparison. 1206.156 Transportation allowances— general. 1206.157 Determination of transportation allowances. 1206.158 Processing allowances—general. 1206.159 Determination of processing allowances. 1206.160 Operating allowances. Subpart D—Federal Gas § 1206.150 Purpose and scope. (a) This subpart is applicable to all gas production from Federal oil and gas leases. The purpose of this subpart is to establish the value of production for royalty purposes consistent with the mineral leasing laws, other applicable laws and lease terms. (b) If the regulations in this subpart are inconsistent with: (1) A Federal statute; (2) A settlement agreement between the United States and a lessee resulting from administrative or judicial litigation; (3) A written agreement between the lessee and the ONRR Director establishing a method to determine the value of production from any lease that ONRR expects at least would approximate the value established under this subpart; or (4) An express provision of an oil and gas lease subject to this subpart; then the statute, settlement agreement, written agreement, or lease provision will govern to the extent of the inconsistency. (c) All royalty payments made to ONRR are subject to audit and adjustment. (d) The regulations in this subpart are intended to ensure that the E:\FR\FM\07AUR3.SGM 07AUR3 36964 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations administration of oil and gas leases is discharged in accordance with the requirements of the governing mineral leasing laws and lease terms. mstockstill on DSK30JT082PROD with RULES3 § 1206.151 Definitions. For purposes of this subpart: Affiliate means a person who controls, is controlled by, or is under common control with another person. For purposes of this subpart: (1) Ownership or common ownership of more than 50 percent of the voting securities, or instruments of ownership, or other forms of ownership, of another person constitutes control. Ownership of less than 10 percent constitutes a presumption of noncontrol that ONRR may rebut. (2) If there is ownership or common ownership of 10 through 50 percent of the voting securities or instruments of ownership, or other forms of ownership, of another person, ONRR will consider the following factors in determining whether there is control under the circumstances of a particular case: (i) The extent to which there are common officers or directors; (ii) With respect to the voting securities, or instruments of ownership, or other forms of ownership: The percentage of ownership or common ownership, the relative percentage of ownership or common ownership compared to the percentage(s) of ownership by other persons, whether a person is the greatest single owner, or whether there is an opposing voting bloc of greater ownership; (iii) Operation of a lease, plant, pipeline, or other facility; (iv) The extent of participation by other owners in operations and day-today management of a lease, plant, pipeline, or other facility; and (v) Other evidence of power to exercise control over or common control with another person. (3) Regardless of any percentage of ownership or common ownership, relatives, either by blood or marriage, are affiliates. Allowance means a deduction in determining value for royalty purposes. Processing allowance means an allowance for the reasonable, actual costs of processing gas determined under this subpart. Transportation allowance means an allowance for the reasonable, actual costs of moving unprocessed gas, residue gas, or gas plant products to a point of sale or delivery off the lease, unit area, or communitized area, or away from a processing plant. The transportation allowance does not include gathering costs. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 Area means a geographic region at least as large as the defined limits of an oil and/or gas field, in which oil and/ or gas lease products have similar quality, economic, and legal characteristics. Arm’s-length contract means a contract or agreement between independent persons who are not affiliates and who have opposing economic interests regarding that contract. To be considered arm’s length for any production month, a contract must satisfy this definition for that month, as well as when the contract was executed. Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Federal leases. BLM means the Bureau of Land Management of the Department of the Interior. BOEM means the Bureau of Ocean Energy Management of the Department of the Interior. BSEE means the Bureau of Safety and Environmental Enforcement of the Department of the Interior. Compression means the process of raising the pressure of gas. Condensate means liquid hydrocarbons (normally exceeding 40 degrees of API gravity) recovered at the surface without resorting to processing. Condensate is the mixture of liquid hydrocarbons that results from condensation of petroleum hydrocarbons existing initially in a gaseous phase in an underground reservoir. Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation. Field means a geographic region situated over one or more subsurface oil and gas reservoirs encompassing at least the outermost boundaries of all oil and gas accumulations known to be within those reservoirs vertically projected to the land surface. Onshore fields are usually given names and their official boundaries are often designated by oil and gas regulatory agencies in the respective States in which the fields are located. Outer Continental Shelf (OCS) fields are named and their boundaries are designated by BOEM. Gas means any fluid, either combustible or noncombustible, hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and which has neither independent shape nor PO 00000 Frm 00032 Fmt 4701 Sfmt 4700 volume, but tends to expand indefinitely. It is a substance that exists in a gaseous or rarefied state under standard temperature and pressure conditions. Gas plant products means separate marketable elements, compounds, or mixtures, whether in liquid, gaseous, or solid form, resulting from processing gas, excluding residue gas. Gathering means the movement of lease production to a central accumulation and/or treatment point on the lease, unit or communitized area, or to a central accumulation or treatment point off the lease, unit or communitized area as approved by BLM or BSEE OCS operations personnel for onshore and OCS leases, respectively. Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to an oil and gas lessee for the disposition of the gas, residue gas, and gas plant products produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as dehydration, measurement, and/or gathering to the extent that the lessee is obligated to perform them at no cost to the Federal Government. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds. Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of lease products—or the land area covered by that authorization, whichever is required by the context. Lease products means any leased minerals attributable to, originating from, or allocated to Outer Continental Shelf or onshore Federal leases. Lessee means any person to whom the United States issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility. Like-quality lease products means lease products which have similar chemical, physical, and legal characteristics. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations Marketable condition means lease products which are sufficiently free from impurities and otherwise in a condition that they will be accepted by a purchaser under a sales contract typical for the field or area. Marketing affiliate means an affiliate of the lessee whose function is to acquire only the lessee’s production and to market that production. Minimum royalty means that minimum amount of annual royalty that the lessee must pay as specified in the lease or in applicable leasing regulations. Net-back method (or work-back method) means a method for calculating market value of gas at the lease. Under this method, costs of transportation, processing, or manufacturing are deducted from the proceeds received for the gas, residue gas or gas plant products, and any extracted, processed, or manufactured products, or from the value of the gas, residue gas or gas plant products, and any extracted, processed, or manufactured products, at the first point at which reasonable values for any such products may be determined by a sale pursuant to an arm’s-length contract or comparison to other sales of such products, to ascertain value at the lease. Net output means the quantity of residue gas and each gas plant product that a processing plant produces. Net profit share (for applicable Federal leases) means the specified share of the net profit from production of oil and gas as provided in the agreement. Netting means the deduction of an allowance from the sales value by reporting a net sales value, instead of correctly reporting the deduction as a separate entry on form ONRR–2014. Outer Continental Shelf (OCS) means all submerged lands lying seaward and outside of the area of land beneath navigable waters as defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control. Person means any individual, firm, corporation, association, partnership, consortium, or joint venture (when established as a separate entity). Posted price means the price, net of all adjustments for quality and location, specified in publicly available price bulletins or other price notices available as part of normal business operations for quantities of unprocessed gas, residue gas, or gas plant products in marketable condition. Processing means any process designed to remove elements or VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 compounds (hydrocarbon and nonhydrocarbon) from gas, including absorption, adsorption, or refrigeration. Field processes which normally take place on or near the lease, such as natural pressure reduction, mechanical separation, heating, cooling, dehydration, and compression, are not considered processing. The changing of pressures and/or temperatures in a reservoir is not considered processing. Residue gas means that hydrocarbon gas consisting principally of methane resulting from processing gas. Sales type code means the contract type or general disposition (e.g., arm’slength or non-arm’s-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm’s-length or non-arm’s-length nature of a transportation or processing allowance. Section 6 lease means an OCS lease subject to section 6 of the Outer Continental Shelf Lands Act, as amended, 43 U.S.C. 1335. Spot sales agreement means a contract wherein a seller agrees to sell to a buyer a specified amount of unprocessed gas, residue gas, or gas plant products at a specified price over a fixed period, usually of short duration, which does not normally require a cancellation notice to terminate, and which does not contain an obligation, nor imply an intent, to continue in subsequent periods. Warranty contract means a long-term contract entered into prior to 1970, including any amendments thereto, for the sale of gas wherein the producer agrees to sell a specific amount of gas and the gas delivered in satisfaction of this obligation may come from fields or sources outside of the designated fields. § 1206.152 Valuation standards— unprocessed gas. (a)(1) This section applies to the valuation of all gas that is not processed and all gas that is processed but is sold or otherwise disposed of by the lessee pursuant to an arm’s-length contract prior to processing (including all gas where the lessee’s arm’s-length contract for the sale of that gas prior to processing provides for the value to be determined on the basis of a percentage of the purchaser’s proceeds resulting from processing the gas). This section also applies to processed gas that must be valued prior to processing in accordance with § 1206.155 of this part. Where the lessee’s contract includes a reservation of the right to process the gas and the lessee exercises that right, § 1206.153 of this part shall apply instead of this section. PO 00000 Frm 00033 Fmt 4701 Sfmt 4700 36965 (2) The value of production, for royalty purposes, of gas subject to this subpart shall be the value of gas determined under this section less applicable allowances. (b)(1)(i) The value of gas sold under an arm’s-length contract is the gross proceeds accruing to the lessee except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the burden of demonstrating that its contract is arm’s-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit. For purposes of this section, gas which is sold or otherwise transferred to the lessee’s marketing affiliate and then sold by the marketing affiliate pursuant to an arm’s-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate. Also, where the lessee’s arm’s-length contract for the sale of gas prior to processing provides for the value to be determined based upon a percentage of the purchaser’s proceeds resulting from processing the gas, the value of production, for royalty purposes, shall never be less than a value equivalent to 100 percent of the value of the residue gas attributable to the processing of the lessee’s gas. (ii) In conducting reviews and audits, ONRR will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the gas. If the contract does not reflect the total consideration, then the ONRR may require that the gas sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration. (iii) If the ONRR determines that the gross proceeds accruing to the lessee pursuant to an arm’s-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the gas production be valued pursuant to paragraph (c)(2) or (c)(3) of this section, and in accordance with the notification requirements of paragraph (e) of this section. When ONRR determines that the value may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s value. (iv) How to value over-delivered volumes under a cash-out program: This paragraph applies to situations where a pipeline purchases gas from a lessee E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36966 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations according to a cash-out program under a transportation contract. For all overdelivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the overdelivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if ONRR determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (3) of this section. (2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of gas sold pursuant to a warranty contract shall be determined by ONRR, and due consideration will be given to all valuation criteria specified in this section. The lessee must request a value determination in accordance with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that any value determination for a warranty contract in effect on the effective date of these regulations shall remain in effect until modified by ONRR. (3) ONRR may require a lessee to certify that its arm’s-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the gas. (c) The value of gas subject to this section which is not sold pursuant to an arm’s-length contract shall be the reasonable value determined in accordance with the first applicable of the following methods: (1) The gross proceeds accruing to the lessee pursuant to a sale under its nonarm’s-length contract (or other disposition other than by an arm’slength contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm’s-length contracts for purchases, sales, or other dispositions of like-quality gas in the same field (or, if necessary to obtain a reasonable sample, from the same area). In evaluating the comparability of arm’slength contracts for the purposes of these regulations, the following factors shall be considered: Price, time of execution, duration, market or markets served, terms, quality of gas, volume, and such other factors as may be appropriate to reflect the value of the gas; (2) A value determined by consideration of other information relevant in valuing like-quality gas, including gross proceeds under arm’slength contracts for like-quality gas in VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 the same field or nearby fields or areas, posted prices for gas, prices received in arm’s-length spot sales of gas, other reliable public sources of price or market information, and other information as to the particular lease operation or the saleability of the gas; or (3) A net-back method or any other reasonable method to determine value. (d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the maximum price permitted by Federal law at which gas may be sold is less than the value determined pursuant to this section, then ONRR shall accept such maximum price as the value. For purposes of this section, price limitations set by any State or local government shall not be considered as a maximum price permitted by Federal law. (2) The limitation prescribed in paragraph (d)(1) of this section shall not apply to gas sold pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section. (e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and ONRR will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations. (2) Any Federal lessee will make available upon request to the authorized ONRR or State representatives, to the Office of the Inspector General of the Department of the Interior, or other person authorized to receive such information, arm’s-length sales and volume data for like-quality production sold, purchased or otherwise obtained by the lessee from the field or area or from nearby fields or areas. (3) A lessee shall notify ONRR if it has determined value pursuant to paragraph (c)(2) or (3) of this section. The notification shall be by letter to the ONRR Director for Office of Natural Resources Revenue or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a form ONRR–2014 using a valuation method authorized by paragraph (c)(2) or (3) of this section, and each time there is a change in a method under paragraph (c)(2) or (3) of this section. (f) If ONRR determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, PO 00000 Frm 00034 Fmt 4701 Sfmt 4700 between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by ONRR. The lessee shall also pay interest on that difference computed pursuant to § 1218.54 of this chapter. If the lessee is entitled to a credit, ONRR will provide instructions for the taking of that credit. (g) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to ONRR a value determination method, and may use that method in determining value for royalty purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its proposal. The ONRR shall expeditiously determine the value based upon the lessee’s proposal and any additional information ONRR deems necessary. In making a value determination ONRR may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After ONRR issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section. (h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for lease production, less applicable allowances. (i) The lessee must place gas in marketable condition and market the gas for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee’s gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the gas in marketable condition or to market the gas. (j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. If there is no contract revision or amendment, and the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm’s-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of gas. (k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by ONRR of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed. (l) Certain information submitted to ONRR to support valuation proposals, including transportation or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this subpart are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. mstockstill on DSK30JT082PROD with RULES3 § 1206.153 Valuation standards— processed gas. (a)(1) This section applies to the valuation of all gas that is processed by the lessee and any other gas production to which this subpart applies and that is not subject to the valuation provisions of § 1206.152 of this part. This section applies where the lessee’s contract includes a reservation of the right to process the gas and the lessee exercises that right. (2) The value of production, for royalty purposes, of gas subject to this section shall be the combined value of the residue gas and all gas plant products determined pursuant to this section, plus the value of any condensate recovered downstream of the point of royalty settlement without resorting to processing determined pursuant to § 1206.102 of this part, less applicable transportation allowances and processing allowances determined pursuant to this subpart. (b)(1)(i) The value of residue gas or any gas plant product sold under an arm’s-length contract is the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee shall have the burden of demonstrating that VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 its contract is arm’s-length. The value that the lessee reports for royalty purposes is subject to monitoring, review, and audit. For purposes of this section, residue gas or any gas plant product which is sold or otherwise transferred to the lessee’s marketing affiliate and then sold by the marketing affiliate pursuant to an arm’s-length contract shall be valued in accordance with this paragraph based upon the sale by the marketing affiliate. (ii) In conducting these reviews and audits, ONRR will examine whether or not the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the residue gas or gas plant product. If the contract does not reflect the total consideration, then the ONRR may require that the residue gas or gas plant product sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be less than the gross proceeds accruing to the lessee, including the additional consideration. (iii) If the ONRR determines that the gross proceeds accruing to the lessee pursuant to an arm’s-length contract do not reflect the reasonable value of the residue gas or gas plant product because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the residue gas or gas plant product be valued pursuant to paragraph (c)(2) or (3) of this section, and in accordance with the notification requirements of paragraph (e) of this section. When ONRR determines that the value may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s value. (iv) How to value over-delivered volumes under a cash-out program: This paragraph applies to situations where a pipeline purchases gas from a lessee according to a cash-out program under a transportation contract. For all overdelivered volumes, the royalty value is the price the pipeline is required to pay for volumes within the tolerances for over-delivery specified in the transportation contract. Use the same value for volumes that exceed the overdelivery tolerances even if those volumes are subject to a lower price under the transportation contract. However, if ONRR determines that the price specified in the transportation contract for over-delivered volumes is unreasonably low, the lessee must value all over-delivered volumes under paragraph (c)(2) or (3) of this section. PO 00000 Frm 00035 Fmt 4701 Sfmt 4700 36967 (2) Notwithstanding the provisions of paragraph (b)(1) of this section, the value of residue gas sold pursuant to a warranty contract shall be determined by ONRR, and due consideration will be given to all valuation criteria specified in this section. The lessee must request a value determination in accordance with paragraph (g) of this section for gas sold pursuant to a warranty contract; provided, however, that any value determination for a warranty contract in effect on the effective date of these regulations shall remain in effect until modified by ONRR. (3) ONRR may require a lessee to certify that its arm’s-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the residue gas or gas plant product. (c) The value of residue gas or any gas plant product which is not sold pursuant to an arm’s-length contract shall be the reasonable value determined in accordance with the first applicable of the following methods: (1) The gross proceeds accruing to the lessee pursuant to a sale under its nonarm’s-length contract (or other disposition other than by an arm’slength contract), provided that those gross proceeds are equivalent to the gross proceeds derived from, or paid under, comparable arm’s-length contracts for purchases, sales, or other dispositions of like quality residue gas or gas plant products from the same processing plant (or, if necessary to obtain a reasonable sample, from nearby plants). In evaluating the comparability of arm’s-length contracts for the purposes of these regulations, the following factors shall be considered: Price, time of execution, duration, market or markets served, terms, quality of residue gas or gas plant products, volume, and such other factors as may be appropriate to reflect the value of the residue gas or gas plant products; (2) A value determined by consideration of other information relevant in valuing like-quality residue gas or gas plant products, including gross proceeds under arm’s-length contracts for like-quality residue gas or gas plant products from the same gas plant or other nearby processing plants, posted prices for residue gas or gas plant products, prices received in spot sales of residue gas or gas plant products, other reliable public sources of price or market information, and other information as to the particular lease operation or the saleability of such residue gas or gas plant products; or (3) A net-back method or any other reasonable method to determine value. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36968 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (d)(1) Notwithstanding any other provisions of this section, except paragraph (h) of this section, if the maximum price permitted by Federal law at which any residue gas or gas plant products may be sold is less than the value determined pursuant to this section, then ONRR shall accept such maximum price as the value. For the purposes of this section, price limitations set by any State or local government shall not be considered as a maximum price permitted by Federal law. (2) The limitation prescribed by paragraph (d)(1) of this section shall not apply to residue gas sold pursuant to a warranty contract and valued pursuant to paragraph (b)(2) of this section. (e)(1) Where the value is determined pursuant to paragraph (c) of this section, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and ONRR will direct a lessee to use a different value if it determines upon review or audit that the reported value is inconsistent with the requirements of these regulations. (2) Any Federal lessee will make available upon request to the authorized ONRR or State representatives, to the Office of the Inspector General of the Department of the Interior, or other persons authorized to receive such information, arm’s-length sales and volume data for like-quality residue gas and gas plant products sold, purchased or otherwise obtained by the lessee from the same processing plant or from nearby processing plants. (3) A lessee shall notify ONRR if it has determined any value pursuant to paragraph (c)(2) or (3) of this section. The notification shall be by letter to the ONRR Director for Office of Natural Resources or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this paragraph is a one-time notification due no later than the end of the month following the month the lessee first reports royalties on a form ONRR–2014 using a valuation method authorized by paragraph (c)(2) or (3) of this section, and each time there is a change in a method under paragraph (c)(2) or (3) of this section. (f) If ONRR determines that a lessee has not properly determined value, the lessee shall pay the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by ONRR. The lessee shall also pay interest computed on that difference pursuant to § 1218.54 of this chapter. If the lessee is VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 entitled to a credit, ONRR will provide instructions for the taking of that credit. (g) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to ONRR a value determination method, and may use that method in determining value for royalty purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its proposal. The ONRR shall expeditiously determine the value based upon the lessee’s proposal and any additional information ONRR deems necessary. In making a value determination, ONRR may use any of the valuation criteria authorized by this subpart. That determination shall remain effective for the period stated therein. After ONRR issues its determination, the lessee shall make the adjustments in accordance with paragraph (f) of this section. (h) Notwithstanding any other provision of this section, under no circumstances shall the value of production for royalty purposes be less than the gross proceeds accruing to the lessee for residue gas and/or any gas plant products, less applicable transportation allowances and processing allowances determined pursuant to this subpart. (i) The lessee must place residue gas and gas plant products in marketable condition and market the residue gas and gas plant products for the mutual benefit of the lessee and the lessor at no cost to the Federal Government. Where the value established under this section is determined by a lessee’s gross proceeds, that value will be increased to the extent that the gross proceeds have been reduced because the purchaser, or any other person, is providing certain services the cost of which ordinarily is the responsibility of the lessee to place the residue gas or gas plant products in marketable condition or to market the residue gas and gas plant products. (j) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm’s-length contract. If the lessee makes timely application for a price increase or benefit allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until PO 00000 Frm 00036 Fmt 4701 Sfmt 4700 monies or consideration resulting from the price increase or additional benefits are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part, or timely, for a quantity of residue gas or gas plant product. (k) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by ONRR of value under this section shall be considered final or binding against the Federal Government or its beneficiaries until the audit period is formally closed. (l) Certain information submitted to ONRR to support valuation proposals, including transportation allowances, processing allowances or extraordinary cost allowances, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any data specified by law to be privileged, confidential, or otherwise exempt, will be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. § 1206.154 Determination of quantities and qualities for computing royalties. (a)(1) Royalties shall be computed on the basis of the quantity and quality of unprocessed gas at the point of royalty settlement approved by BLM or BSEE for onshore and OCS leases, respectively. (2) If the value of gas determined pursuant to § 1206.152 of this subpart is based upon a quantity and/or quality that is different from the quantity and/ or quality at the point of royalty settlement, as approved by BLM or BSEE, that value shall be adjusted for the differences in quantity and/or quality. (b)(1) For residue gas and gas plant products, the quantity basis for computing royalties due is the monthly net output of the plant even though residue gas and/or gas plant products may be in temporary storage. (2) If the value of residue gas and/or gas plant products determined pursuant to § 1206.153 of this subpart is based upon a quantity and/or quality of residue gas and/or gas plant products that is different from that which is attributable to a lease, determined in accordance with paragraph (c) of this section, that value shall be adjusted for E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations the differences in quantity and/or quality. (c) The quantity of the residue gas and gas plant products attributable to a lease shall be determined according to the following procedure: (1) When the net output of the processing plant is derived from gas obtained from only one lease, the quantity of the residue gas and gas plant products on which computations of royalty are based is the net output of the plant. (2) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of uniform content, the quantity of the residue gas and gas plant products allocable to each lease shall be in the same proportions as the ratios obtained by dividing the amount of gas delivered to the plant from each lease by the total amount of gas delivered from all leases. (3) When the net output of a processing plant is derived from gas obtained from more than one lease producing gas of nonuniform content, the quantity of the residue gas allocable to each lease will be determined by multiplying the amount of gas delivered to the plant from the lease by the residue gas content of the gas, and dividing the arithmetical product thus obtained by the sum of the similar arithmetical products separately obtained for all leases from which gas is delivered to the plant, and then multiplying the net output of the residue gas by the arithmetic quotient obtained. The net output of gas plant products allocable to each lease will be determined by multiplying the amount of gas delivered to the plant from the lease by the gas plant product content of the gas, and dividing the arithmetical product thus obtained by the sum of the similar arithmetical products separately obtained for all leases from which gas is delivered to the plant, and then multiplying the net output of each gas plant product by the arithmetic quotient obtained. (4) A lessee may request ONRR approval of other methods for determining the quantity of residue gas and gas plant products allocable to each lease. If approved, such method will be applicable to all gas production from Federal leases that is processed in the same plant. (d)(1) No deductions may be made from the royalty volume or royalty value for actual or theoretical losses. Any actual loss of unprocessed gas that may be sustained prior to the royalty settlement metering or measurement point will not be subject to royalty provided that such loss is determined to VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 have been unavoidable by BLM or BSEE, as appropriate. (2) Except as provided in paragraph (d)(1) of this section and § 1202.151(c), royalties are due on 100 percent of the volume determined in accordance with paragraphs (a) through (c) of this section. There can be no reduction in that determined volume for actual losses after the quantity basis has been determined or for theoretical losses that are claimed to have taken place. Royalties are due on 100 percent of the value of the unprocessed gas, residue gas, and/or gas plant products as provided in this subpart, less applicable allowances. There can be no deduction from the value of the unprocessed gas, residue gas, and/or gas plant products to compensate for actual losses after the quantity basis has been determined, or for theoretical losses that are claimed to have taken place. § 1206.155 Accounting for comparison. (a) Except as provided in paragraph (b) of this section, where the lessee (or a person to whom the lessee has transferred gas pursuant to a non-arm’slength contract or without a contract) processes the lessee’s gas and after processing the gas the residue gas is not sold pursuant to an arm’s-length contract, the value, for royalty purposes, shall be the greater of: (1) The combined value, for royalty purposes, of the residue gas and gas plant products resulting from processing the gas determined pursuant to § 1206.153 of this subpart, plus the value, for royalty purposes, of any condensate recovered downstream of the point of royalty settlement without resorting to processing determined pursuant to § 1206.102 of this subpart; or (2) The value, for royalty purposes, of the gas prior to processing determined in accordance with § 1206.152 of this subpart. (b) The requirement for accounting for comparison contained in the terms of leases will govern as provided in § 1206.150(b) of this subpart. When accounting for comparison is required by the lease terms, such accounting for comparison shall be determined in accordance with paragraph (a) of this section. § 1206.156 general. Transportation allowances— (a) Where the value of gas has been determined pursuant to § 1206.152 or § 1206.153 of this subpart at a point (e.g., sales point or point of value determination) off the lease, ONRR shall allow a deduction for the reasonable actual costs incurred by the lessee to PO 00000 Frm 00037 Fmt 4701 Sfmt 4700 36969 transport unprocessed gas, residue gas, and gas plant products from a lease to a point off the lease including, if appropriate, transportation from the lease to a gas processing plant off the lease and from the plant to a point away from the plant. (b) Transportation costs must be allocated among all products produced and transported as provided in § 1206.157. (c)(1) Except as provided in paragraph (c)(3) of this section, for unprocessed gas valued in accordance with § 1206.152 of this subpart, the transportation allowance deduction on the basis of a sales type code may not exceed 50 percent of the value of the unprocessed gas determined under § 1206.152 of this subpart. (2) Except as provided in paragraph (c)(3) of this section, for gas production valued in accordance with § 1206.153 of this subpart, the transportation allowance deduction on the basis of a sales type code may not exceed 50 percent of the value of the residue gas or gas plant product determined under § 1206.153 of this subpart. For purposes of this section, natural gas liquids will be considered one product. (3) Upon request of a lessee, ONRR may approve a transportation allowance deduction in excess of the limitations prescribed by paragraphs (c)(1) and (2) of this section. The lessee must demonstrate that the transportation costs incurred in excess of the limitations prescribed in paragraphs (c)(1) and (2) of this section were reasonable, actual, and necessary. An application for exception (using form ONRR–4393, Request to Exceed Regulatory Allowance Limitation) must contain all relevant and supporting documentation necessary for ONRR to make a determination. Under no circumstances may the value for royalty purposes under any sales type code be reduced to zero. (d) If, after a review or audit, ONRR determines that a lessee has improperly determined a transportation allowance authorized by this subpart, then the lessee must pay any additional royalties, plus interest, determined in accordance with § 1218.54 of this chapter, or will be entitled to a credit, with interest. If the lessee takes a deduction for transportation on form ONRR–2014 by improperly netting the allowance against the sales value of the unprocessed gas, residue gas, and gas plant products instead of reporting the allowance as a separate entry, ONRR may assess a civil penalty under 30 CFR part 1241. E:\FR\FM\07AUR3.SGM 07AUR3 36970 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations mstockstill on DSK30JT082PROD with RULES3 § 1206.157 Determination of transportation allowances. (a) Arm’s-length transportation contracts. (1)(i) For transportation costs incurred by a lessee under an arm’slength contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the unprocessed gas, residue gas and/or gas plant products under that contract, except as provided in paragraphs (a)(1)(ii) and (iii) of this section, subject to monitoring, review, audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm’s-length. ONRR’s prior approval is not required before a lessee may deduct costs incurred under an arm’s-length contract. Such allowances shall be subject to the provisions of paragraph (f) of this section. The lessee must claim a transportation allowance by reporting it as a separate entry on the form ONRR– 2014. (ii) In conducting reviews and audits, ONRR will examine whether or not the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration, then the ONRR may require that the transportation allowance be determined in accordance with paragraph (b) of this section. (iii) If the ONRR determines that the consideration paid pursuant to an arm’slength transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the transportation may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s transportation costs. (2)(i) If an arm’s-length transportation contract includes more than one product in a gaseous phase and the transportation costs attributable to each product cannot be determined from the contract, the total transportation costs shall be allocated in a consistent and equitable manner to each of the products transported in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all products in the gaseous phase (excluding waste products which have VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 no value). Except as provided in this paragraph, no allowance may be taken for the costs of transporting lease production which is not royalty bearing without ONRR approval. (ii) Notwithstanding the requirements of paragraph (a)(2)(i) of this section, the lessee may propose to ONRR a cost allocation method on the basis of the values of the products transported. ONRR shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part. (3) If an arm’s-length transportation contract includes both gaseous and liquid products and the transportation costs attributable to each cannot be determined from the contract, the lessee shall propose an allocation procedure to ONRR. The lessee may use the transportation allowance determined in accordance with its proposed allocation procedure until ONRR issues its determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. ONRR shall then determine the gas transportation allowance based upon the lessee’s proposal and any additional information ONRR deems necessary. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on the form ONRR–2014. (4) Where the lessee’s payments for transportation under an arm’s-length contract are not based on a dollar per unit, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section. (5) Where an arm’s-length sales contract price or a posted price includes a provision whereby the listed price is reduced by a transportation factor, ONRR will not consider the transportation factor to be a transportation allowance. The transportation factor may be used in determining the lessee’s gross proceeds for the sale of the product. The transportation factor may not exceed 50 percent of the base price of the product without ONRR approval. (b) Non-arm’s-length or no contract. (1) If a lessee has a non-arm’s-length transportation contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee’s reasonable actual costs as provided in this paragraph. All transportation allowances deducted under a non-arm’s-length or no contract situation are subject to monitoring, review, audit, and adjustment. The lessee must claim a transportation PO 00000 Frm 00038 Fmt 4701 Sfmt 4700 allowance by reporting it as a separate entry on the form ONRR–2014. When necessary or appropriate, ONRR may direct a lessee to modify its estimated or actual transportation allowance deduction. (2) The transportation allowance for non-arm’s-length or no-contract situations shall be based upon the lessee’s actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable investment in the transportation system multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system. (i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document. (ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document. (iii) Overhead directly attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses. (iv) A lessee may use either depreciation or a return on depreciable capital investment. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of the ONRR. (A) To compute depreciation, the lessee may elect to use either a straightline depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value. (B) The ONRR shall allow as a cost an amount equal to the allowable initial capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service after March 1, 1988. (v) The rate of return must be 1.3 times the industrial rate associated with Standard & Poor’s BBB rating. The BBB rate must be the monthly average rate as published in Standard & Poor’s Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year. (3)(i) The deduction for transportation costs shall be determined on the basis of the lessee’s cost of transporting each product through each individual transportation system. Where more than one product in a gaseous phase is transported, the allocation of costs to each of the products transported shall be made in a consistent and equitable manner in the same proportion as the ratio of the volume of each product (excluding waste products which have no value) to the volume of all products in the gaseous phase (excluding waste products which have no value). Except as provided in this paragraph, the lessee may not take an allowance for transporting a product which is not royalty bearing without ONRR approval. (ii) Notwithstanding the requirements of paragraph (b)(3)(i) of this section, the lessee may propose to the ONRR a cost allocation method on the basis of the values of the products transported. ONRR shall approve the method unless it determines that it is not consistent with the purposes of the regulations in this part. (4) Where both gaseous and liquid products are transported through the same transportation system, the lessee shall propose a cost allocation procedure to ONRR. The lessee may use the transportation allowance determined in accordance with its proposed allocation procedure until ONRR issues its determination on the acceptability of the cost allocation. The lessee shall submit all relevant data to support its proposal. ONRR shall then determine the transportation allowance based upon the lessee’s proposal and any additional information ONRR deems necessary. The lessee must submit the allocation proposal within 3 VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 months of claiming the allocated deduction on the form ONRR–2014. (5) You may apply for an exception from the requirement to compute actual costs under paragraphs (b)(1) through (4) of this section. (i) ONRR will grant the exception if: (A) The transportation system has a tariff filed with the Federal Energy Regulatory Commission (FERC) or a State regulatory agency, that FERC or the State regulatory agency has permitted to become effective, and (B) Third parties are paying prices, including discounted prices, under the tariff to transport gas on the system under arm’s-length transportation contracts. (ii) If ONRR approves the exception, you must calculate your transportation allowance for each production month based on the lesser of the volumeweighted average of the rates paid by the third parties under arm’s-length transportation contracts during that production month or the non-arm’slength payment by the lessee to the pipeline. (iii) If during any production month there are no prices paid under the tariff by third parties to transport gas on the system under arm’s-length transportation contracts, you may use the volume-weighted average of the rates paid by third parties under arm’slength transportation contracts in the most recent preceding production month in which the tariff remains in effect and third parties paid such rates, for up to five successive production months. You must use the non-arm’slength payment by the lessee to the pipeline if it is less than the volumeweighted average of the rates paid by third parties under arm’s-length contracts. (c) Reporting requirements—(1) Arm’s-length contracts. (i) You must use a separate entry on form ONRR–2014 to notify ONRR of a transportation allowance. (ii) ONRR may require you to submit arm’s-length transportation contracts, production agreements, operating agreements, and related documents. Recordkeeping requirements are found at part 1207 of this chapter. (iii) You may not use a transportation allowance that was in effect before March 1, 1988. You must use the provisions of this subpart to determine your transportation allowance. (2) Non-arm’s-length or no contract. (i) You must use a separate entry on form ONRR–2014 to notify ONRR of a transportation allowance. (ii) For new transportation facilities or arrangements, base your initial deduction on estimates of allowable gas PO 00000 Frm 00039 Fmt 4701 Sfmt 4700 36971 transportation costs for the applicable period. Use the most recently available operations data for the transportation system or, if such data are not available, use estimates based on data for similar transportation systems. Paragraph (e) of this section will apply when you amend your report based on your actual costs. (iii) ONRR may require you to submit all data used to calculate the allowance deduction. Recordkeeping requirements are found at part 1207 of this chapter. (iv) If you are authorized under paragraph (b)(5) of this section to use an exception to the requirement to calculate your actual transportation costs, you must follow the reporting requirements of paragraph (c)(1) of this section. (v) You may not use a transportation allowance that was in effect before March 1, 1988. You must use the provisions of this subpart to determine your transportation allowance. (d) Interest and assessments. (1) If a lessee deducts a transportation allowance on its form ONRR–2014 that exceeds 50 percent of the value of the gas transported without obtaining prior approval of ONRR under § 1206.156, the lessee shall pay interest on the excess allowance amount taken from the date such amount is taken to the date the lessee files an exception request with ONRR. (2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment. (3) Interest required to be paid by this section shall be determined in accordance with § 1218.54 of this chapter. (e) Adjustments. (1) If the actual transportation allowance is less than the amount the lessee has taken on form ONRR–2014 for each month during the allowance reporting period, the lessee shall be required to pay additional royalties due plus interest computed under § 1218.54 of this chapter from the allowance reporting period when the lessee took the deduction to the date the lessee repays the difference to ONRR. If the actual transportation allowance is greater than the amount the lessee has taken on form ONRR–2014 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest. (2) For lessees transporting production from onshore Federal leases, the lessee must submit a corrected form ONRR–2014 to reflect actual costs, together with any payment, in accordance with instructions provided by ONRR. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36972 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (3) For lessees transporting gas production from leases on the OCS, if the lessee’s estimated transportation allowance exceeds the allowance based on actual costs, the lessee must submit a corrected form ONRR–2014 to reflect actual costs, together with its payment, in accordance with instructions provided by ONRR. If the lessee’s estimated transportation allowance is less than the allowance based on actual costs, the refund procedure will be specified by ONRR. (f) Allowable costs in determining transportation allowances. You may include, but are not limited to (subject to the requirements of paragraph (g) of this section), the following costs in determining the arm’s-length transportation allowance under paragraph (a) of this section or the nonarm’s-length transportation allowance under paragraph (b) of this section. You may not use any cost as a deduction that duplicates all or part of any other cost that you use under this paragraph. (1) Firm demand charges paid to pipelines. You may deduct firm demand charges or capacity reservation fees paid to a pipeline, including charges or fees for unused firm capacity that you have not sold before you report your allowance. If you receive a payment from any party for release or sale of firm capacity after reporting a transportation allowance that included the cost of that unused firm capacity, or if you receive a payment or credit from the pipeline for penalty refunds, rate case refunds, or other reasons, you must reduce the firm demand charge claimed on the form ONRR–2014 by the amount of that payment. You must modify the form ONRR–2014 by the amount received or credited for the affected reporting period, and pay any resulting royalty and late payment interest due; (2) Gas supply realignment (GSR) costs. The GSR costs result from a pipeline reforming or terminating supply contracts with producers to implement the restructuring requirements of FERC Orders in 18 CFR part 284; (3) Commodity charges. The commodity charge allows the pipeline to recover the costs of providing service; (4) Wheeling costs. Hub operators charge a wheeling cost for transporting gas from one pipeline to either the same or another pipeline through a market center or hub. A hub is a connected manifold of pipelines through which a series of incoming pipelines are interconnected to a series of outgoing pipelines; (5) Gas Research Institute (GRI) fees. The GRI conducts research, development, and commercialization VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 programs on natural gas related topics for the benefit of the U.S. gas industry and gas customers. GRI fees are allowable provided such fees are mandatory in FERC-approved tariffs; (6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to pipelines to pay for its operating expenses; (7) Payments (either volumetric or in value) for actual or theoretical losses. However, theoretical losses are not deductible in non-arm’s-length transportation arrangements unless the transportation allowance is based on arm’s-length transportation rates charged under a FERC- or State regulatory-approved tariff under paragraph (b)(5) of this section. If you receive volumes or credit for line gain, you must reduce your transportation allowance accordingly and pay any resulting royalties and late payment interest due; (8) Temporary storage services. This includes short duration storage services offered by market centers or hubs (commonly referred to as ‘‘parking’’ or ‘‘banking’’), or other temporary storage services provided by pipeline transporters, whether actual or provided as a matter of accounting. Temporary storage is limited to 30 days or less; and (9) Supplemental costs for compression, dehydration, and treatment of gas. ONRR allows these costs only if such services are required for transportation and exceed the services necessary to place production into marketable condition required under §§ 1206.152(i) and 1206.153(i) of this part. (10) Costs of surety. You may deduct the costs of securing a letter of credit, or other surety, that the pipeline requires you as a shipper to maintain under an arm’s-length transportation contract. (g) Nonallowable costs in determining transportation allowances. Lessees may not include the following costs in determining the arm’s-length transportation allowance under paragraph (a) of this section or the nonarm’s-length transportation allowance under paragraph (b) of this section: (1) Fees or costs incurred for storage. This includes storing production in a storage facility, whether on or off the lease, for more than 30 days; (2) Aggregator/marketer fees. This includes fees you pay to another person (including your affiliates) to market your gas, including purchasing and reselling the gas, or finding or maintaining a market for the gas production; (3) Penalties you incur as shipper. These penalties include, but are not limited to: PO 00000 Frm 00040 Fmt 4701 Sfmt 4700 (i) Over-delivery cash-out penalties. This includes the difference between the price the pipeline pays you for overdelivered volumes outside the tolerances and the price you receive for over-delivered volumes within the tolerances; (ii) Scheduling penalties. This includes penalties you incur for differences between daily volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point; (iii) Imbalance penalties. This includes penalties you incur (generally on a monthly basis) for differences between volumes delivered into the pipeline and volumes scheduled or nominated at a receipt or delivery point; and (iv) Operational penalties. This includes fees you incur for violation of the pipeline’s curtailment or operational orders issued to protect the operational integrity of the pipeline; (4) Intra-hub transfer fees. These are fees you pay to hub operators for administrative services (e.g., title transfer tracking) necessary to account for the sale of gas within a hub; (5) Fees paid to brokers. This includes fees paid to parties who arrange marketing or transportation, if such fees are separately identified from aggregator/marketer fees; (6) Fees paid to scheduling service providers. This includes fees paid to parties who provide scheduling services, if such fees are separately identified from aggregator/marketer fees; (7) Internal costs. This includes salaries and related costs, rent/space costs, office equipment costs, legal fees, and other costs to schedule, nominate, and account for sale or movement of production; and (8) Other nonallowable costs. Any cost you incur for services you are required to provide at no cost to the lessor. (h) Other transportation cost determinations. Use this section when calculating transportation costs to establish value using a netback procedure or any other procedure that requires deduction of transportation costs. § 1206.158 general. Processing allowances— (a) Where the value of gas is determined pursuant to § 1206.153 of this subpart, a deduction shall be allowed for the reasonable actual costs of processing. (b) Processing costs must be allocated among the gas plant products. A separate processing allowance must be determined for each gas plant product E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations and processing plant relationship. Natural gas liquids (NGL’s) shall be considered as one product. (c)(1) Except as provided in paragraph (d)(2) of this section, the processing allowance shall not be applied against the value of the residue gas. Where there is no residue gas ONRR may designate an appropriate gas plant product against which no allowance may be applied. (2) Except as provided in paragraph (c)(3) of this section, the processing allowance deduction on the basis of an individual product shall not exceed 66 2⁄3 percent of the value of each gas plant product determined in accordance with § 1206.153 of this subpart (such value to be reduced first for any transportation allowances related to postprocessing transportation authorized by § 1206.156 of this subpart). (3) Upon request of a lessee, ONRR may approve a processing allowance in excess of the limitation prescribed by paragraph (c)(2) of this section. The lessee must demonstrate that the processing costs incurred in excess of the limitation prescribed in paragraph (c)(2) of this section were reasonable, actual, and necessary. An application for exception (using form ONRR–4393, Request to Exceed Regulatory Allowance Limitation) shall contain all relevant and supporting documentation for ONRR to make a determination. Under no circumstances shall the value for royalty purposes of any gas plant product be reduced to zero. (d)(1) Except as provided in paragraph (d)(2) of this section, no processing cost deduction shall be allowed for the costs of placing lease products in marketable condition, including dehydration, separation, compression, or storage, even if those functions are performed off the lease or at a processing plant. Where gas is processed for the removal of acid gases, commonly referred to as ‘‘sweetening,’’ no processing cost deduction shall be allowed for such costs unless the acid gases removed are further processed into a gas plant product. In such event, the lessee shall be eligible for a processing allowance as determined in accordance with this subpart. However, ONRR will not grant any processing allowance for processing lease production which is not royalty bearing. (2)(i) If the lessee incurs extraordinary costs for processing gas production from a gas production operation, it may apply to ONRR for an allowance for those costs which shall be in addition to any other processing allowance to which the lessee is entitled pursuant to this section. Such an allowance may be granted only if the lessee can VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 demonstrate that the costs are, by reference to standard industry conditions and practice, extraordinary, unusual, or unconventional. (ii) Prior ONRR approval to continue an extraordinary processing cost allowance is not required. However, to retain the authority to deduct the allowance the lessee must report the deduction to ONRR in a form and manner prescribed by ONRR. (e) If ONRR determines that a lessee has improperly determined a processing allowance authorized by this subpart, then the lessee must pay any additional royalties, plus interest determined under § 1218.54 of this chapter, or will be entitled to a credit with interest. If the lessee takes a deduction for processing on form ONRR–2014 by improperly netting the allowance against the sales value of the gas plant products instead of reporting the allowance as a separate entry, ONRR may assess a civil penalty under 30 CFR part 1241. § 1206.159 Determination of processing allowances. (a) Arm’s-length processing contracts. (1)(i) For processing costs incurred by a lessee under an arm’s-length contract, the processing allowance shall be the reasonable actual costs incurred by the lessee for processing the gas under that contract, except as provided in paragraphs (a)(1)(ii) and (iii) of this section, subject to monitoring, review, audit, and adjustment. The lessee shall have the burden of demonstrating that its contract is arm’s-length. ONRR’s prior approval is not required before a lessee may deduct costs incurred under an arm’s-length contract. The lessee must claim a processing allowance by reporting it as a separate entry on the form ONRR–2014. (ii) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the processor for the processing. If the contract reflects more than the total consideration, then the ONRR may require that the processing allowance be determined in accordance with paragraph (b) of this section. (iii) If ONRR determines that the consideration paid pursuant to an arm’slength processing contract does not reflect the reasonable value of the processing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and lessor, then ONRR shall require that the processing allowance be PO 00000 Frm 00041 Fmt 4701 Sfmt 4700 36973 determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the processing may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s processing costs. (2) If an arm’s-length processing contract includes more than one gas plant product and the processing costs attributable to each product can be determined from the contract, then the processing costs for each gas plant product shall be determined in accordance with the contract. No allowance may be taken for the costs of processing lease production which is not royalty-bearing. (3) If an arm’s-length processing contract includes more than one gas plant product and the processing costs attributable to each product cannot be determined from the contract, the lessee shall propose an allocation procedure to ONRR. The lessee may use its proposed allocation procedure until ONRR issues its determination. The lessee shall submit all relevant data to support its proposal. ONRR shall then determine the processing allowance based upon the lessee’s proposal and any additional information ONRR deems necessary. No processing allowance will be granted for the costs of processing lease production which is not royalty bearing. The lessee must submit the allocation proposal within 3 months of claiming the allocated deduction on form ONRR– 2014. (4) Where the lessee’s payments for processing under an arm’s-length contract are not based on a dollar per unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section. (b) Non-arm’s-length or no contract. (1) If a lessee has a non-arm’s-length processing contract or has no contract, including those situations where the lessee performs processing for itself, the processing allowance will be based upon the lessee’s reasonable actual costs as provided in this paragraph. All processing allowances deducted under a non-arm’s-length or no-contract situation are subject to monitoring, review, audit, and adjustment. The lessee must claim a processing allowance by reflecting it as a separate entry on the form ONRR–2014. When necessary or appropriate, ONRR may direct a lessee to modify its estimated or actual processing allowance. (2) The processing allowance for nonarm’s-length or no-contract situations shall be based upon the lessee’s actual costs for processing during the reporting E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36974 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the initial depreciable investment in the processing plant multiplied by a rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those costs for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the processing plant. (i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document. (ii) Allowable maintenance expenses include: Maintenance of the processing plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document. (iii) Overhead directly attributable and allocable to the operation and maintenance of the processing plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses. (iv) A lessee may use either depreciation or a return on depreciable capital investment. When a lessee has elected to use either method for a processing plant, the lessee may not later elect to change to the other alternative without approval of the ONRR. (A) To compute depreciation, the lessee may elect to use either a straightline depreciation method based on the life of equipment or on the life of the reserves which the processing plant services, or a unit-of-production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a processing plant shall not alter the depreciation schedule established by the original processor/lessee for purposes of the allowance calculation. With or without a change in ownership, a processing plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value. (B) The ONRR shall allow as a cost an amount equal to the allowable initial capital investment in the processing plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 shall be provided for depreciation. This alternative shall apply only to plants first placed in service after March 1, 1988. (v) The rate of return must be the industrial rate associated with Standard and Poor’s BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor’s Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year. (3) The processing allowance for each gas plant product shall be determined based on the lessee’s reasonable and actual cost of processing the gas. Allocation of costs to each gas plant product shall be based upon generally accepted accounting principles. The lessee may not take an allowance for the costs of processing lease production which is not royalty bearing. (4) A lessee may apply to ONRR for an exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) through (b)(3) of this section. The ONRR may grant the exception only if: (i) The lessee has arm’s-length contracts for processing other gas production at the same processing plant; and (ii) at least 50 percent of the gas processed annually at the plant is processed pursuant to arm’slength processing contracts; if the ONRR grants the exception, the lessee shall use as its processing allowance the volume weighted average prices charged other persons pursuant to arm’s-length contracts for processing at the same plant. (c) Reporting requirements—(1) Arm’s-length contracts. (i) The lessee must notify ONRR of an allowance based on incurred costs by using a separate entry on the form ONRR–2014. (ii) ONRR may require that a lessee submit arm’s-length processing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR. (2) Non-arm’s-length or no contract. (i) The lessee must notify ONRR of an allowance based on the incurred costs by using a separate entry on the form ONRR–2014. (ii) For new processing plants, the lessee’s initial deduction shall include estimates of the allowable gas processing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant or, if such data are not available, the lessee shall use estimates based upon industry data for similar gas processing plants. (iii) Upon request by ONRR, the lessee shall submit all data used to prepare the PO 00000 Frm 00042 Fmt 4701 Sfmt 4700 allowance deduction. The data shall be provided within a reasonable period of time, as determined by ONRR. (iv) If the lessee is authorized to use the volume weighted average prices charged other persons as its processing allowance in accordance with paragraph (b)(4) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section. (d) Interest. (1) If a lessee deducts a processing allowance on its form ONRR–2014 that exceeds 66 2⁄3 percent of the value of the gas processed without obtaining prior approval of ONRR under § 1206.158, the lessee shall pay interest on the excess allowance amount taken from the date such amount is taken to the date the lessee files an exception request with ONRR. (2) If a lessee erroneously reports a processing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment. (3) Interest required to be paid by this section shall be determined in accordance with § 1218.54 of this chapter. (e) Adjustments. (1) If the actual processing allowance is less than the amount the lessee has taken on form ONRR–2014 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under § 1218.54 of this chapter from the allowance reporting period when the lessee took the deduction to the date the lessee repays the difference to ONRR. If the actual processing allowance is greater than the amount the lessee has taken on form ONRR–2014 for each month during the allowance reporting period, the lessee shall be entitled to a credit with interest. (2) For lessees processing production from onshore Federal leases, the lessee must submit a corrected form ONRR– 2014 to reflect actual costs, together with any payment, in accordance with instructions provided by ONRR. (3) For lessees processing gas production from leases on the OCS, if the lessee’s estimated processing allowance exceeds the allowance based on actual costs, the lessee must submit a corrected form ONRR–2014 to reflect actual costs, together with its payment, in accordance with instructions provided by ONRR. If the lessee’s estimated costs were less than the actual costs, the refund procedure will be specified by ONRR. (f) Other processing cost determinations. The provisions of this section shall apply to determine processing costs when establishing value using a net back valuation E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations procedure or any other procedure that requires deduction of processing costs. § 1206.160 Operating allowances. Notwithstanding any other provisions in these regulations, an operating allowance may be used for the purpose of computing payment obligations when specified in the notice of sale and the lease. The allowance amount or formula shall be specified in the notice of sale and in the lease agreement. ■ 8. Revise subpart F to read as follows: Subpart F—Federal Coal Sec. 1206.250 Purpose and scope. 1206.251 Definitions. 1206.252 Information collection. 1206.253 Coal subject to royalties—general provisions. 1206.254 Quality and quantity measurement standards for reporting and paying royalties. 1206.255 Point of royalty determination. 1206.256 Valuation standards for cents-perton leases. 1206.257 Valuation standards for ad valorem leases. 1206.258 Washing allowances—general. 1206.259 Determination of washing allowances. 1206.260 Allocation of washed coal. 1206.261 Transportation allowances— general. 1206.262 Determination of transportation allowances. 1206.263 [Reserved] 1206.264 In-situ and surface gasification and liquefaction operations. 1206.265 Value enhancement of marketable coal. Subpart F—Federal Coal mstockstill on DSK30JT082PROD with RULES3 § 1206.250 Purpose and scope. (a) This subpart is applicable to all coal produced from Federal coal leases. The purpose of this subpart is to establish the value of coal produced for royalty purposes, of all coal from Federal leases consistent with the mineral leasing laws, other applicable laws and lease terms. (b) If the specific provisions of any statute or settlement agreement between the United States and a lessee resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart then the statute, lease provision, or settlement shall govern to the extent of that inconsistency. (c) All royalty payments made to the Office of Natural Resources Revenue (ONRR) are subject to later audit and adjustment. § 1206.251 Definitions. Ad valorem lease means a lease where the royalty due to the lessor is based VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 upon a percentage of the amount or value of the coal. Allowance means a deduction used in determining value for royalty purposes. Coal washing allowance means an allowance for the reasonable, actual costs incurred by the lessee for coal washing. Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant. Area means a geographic region in which coal has similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named. Arm’s-length contract means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership: (a) Ownership in excess of 50 percent constitutes control; (b) Ownership of 10 through 50 percent creates a presumption of control; and (c) Ownership of less than 10 percent creates a presumption of noncontrol which ONRR may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm’s-length contracts. The ONRR may require the lessee to certify ownership control. To be considered arm’s-length for any production month, a contract must meet the requirements of this definition for that production month as well as when the contract was executed. Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Federal leases. BLM means the Bureau of Land Management of the Department of the Interior. Coal means coal of all ranks from lignite through anthracite. Coal washing means any treatment to remove impurities from coal. Coal washing may include, but is not limited to, operations such as flotation, air, PO 00000 Frm 00043 Fmt 4701 Sfmt 4700 36975 water, or heavy media separation; drying; and related handling (or combination thereof). Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation. Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Federal Government. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Federal royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds. Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States for a Federal coal resource under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of coal—or the land covered by that authorization, whichever is required by the context. Lessee means any person to whom the United States issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility. Like-quality coal means coal that has similar chemical and physical characteristics. Marketable condition means coal that is sufficiently free from impurities and otherwise in a condition that it will be accepted by a purchaser under a sales contract typical for that area. Mine means an underground or surface excavation or series of excavations and the surface or underground support facilities that E:\FR\FM\07AUR3.SGM 07AUR3 36976 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations contribute directly or indirectly to mining, production, preparation, and handling of lease products. Net-back method means a method for calculating market value of coal at the lease or mine. Under this method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds received for the coal at the first point at which reasonable values for the coal may be determined by a sale pursuant to an arm’s-length contract or by comparison to other sales of coal, to ascertain value at the mine. Net output means the quantity of washed coal that a washing plant produces. Netting is the deduction of an allowance from the sales value by reporting a one line net sales value, instead of correctly reporting the deduction as a separate line item on the form ONRR–4430. Person means by individual, firm, corporation, association, partnership, consortium, or joint venture. Sales type code means the contract type or general disposition (e.g., arm’slength or non-arm’s-length) of production from the lease. The sales type code applies to the sales contract, or other disposition, and not to the arm’s-length or non-arm’s-length nature of a transportation or washing allowance. Spot market price means the price received under any sales transaction when planned or actual deliveries span a short period of time, usually not exceeding one year. § 1206.252 Information collection. The information collection requirements contained in this subpart have been approved by the Office of Management and Budget (OMB) under 44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB control numbers are identified in part 1210— Forms and Reports. mstockstill on DSK30JT082PROD with RULES3 § 1206.253 Coal subject to royalties— general provisions. (a) All coal (except coal unavoidably lost as determined by BLM under 43 CFR part 3400) from a Federal lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease. (b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 (c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; i.e., underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Federal leases shall be allocated to such leases regardless of whether it is stored on Federal lands. The lessee shall maintain accurate records to determine to which individual Federal lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid. § 1206.254 Quality and quantity measurement standards for reporting and paying royalties. For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information will be reported on appropriate forms required under 30 CFR part 1210—Forms and Reports. § 1206.255 Point of royalty determination. (a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Federal coal in marketable condition measured at the point of royalty measurement as determined jointly by BLM and ONRR. (b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. ONRR may ask BLM to increase the lease bond to protect the lessor’s interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource. (c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 1206.256(d) of this subpart. § 1206.256 Valuation standards for centsper-ton leases. (a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty on a cents-per-ton (or other quantity) basis. (b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal PO 00000 Frm 00044 Fmt 4701 Sfmt 4700 used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determine by BLM pursuant to 43 CFR part 3400. (c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal. (d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 1206.257 of this subpart, and royalties shall be paid at the royalty rate specified in the readjusted lease. § 1206.257 Valuation standards for ad valorem leases. (a) This section is applicable to coal leases on Federal lands which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the value of coal determined under this section, less applicable coal washing allowances and transportation allowances determined under §§ 1206.258 through 1206.262 of this subpart, or any allowance authorized by § 1206.265 of this subpart. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease. (b)(1) The value of coal that is sold pursuant to an arm’s-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (3), and (5) of this section. The lessee shall have the burden of demonstrating that its contract is arm’s-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit. (2) In conducting reviews and audits, ONRR will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then the ONRR may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (3) If ONRR determines that the gross proceeds accruing to the lessee pursuant to an arm’s-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the coal production be valued pursuant to paragraph (c)(2)(ii), (iii), (iv), or (v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When ONRR determines that the value may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s reported coal value. (4) ONRR may require a lessee to certify that its arm’s-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production. (5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to ONRR’s satisfaction, were not part of the total consideration paid for the purchase of coal production. (c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm’s-length contract shall be determined in accordance with this section. (2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion: (i) The gross proceeds accruing to the lessee pursuant to a sale under its nonarm’s-length contract (or other disposition of produced coal by other than an arm’s-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm’slength contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm’s-length contracts for the purposes of these regulations, the following factors shall be considered: Price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal; VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 (ii) Prices reported for that coal to a public utility commission; (iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy; (iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the saleability of certain types of coal; (v) If a reasonable value cannot be determined using paragraphs (c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back method or any other reasonable method shall be used to determine value. (3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section. (d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require ONRR’s prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and ONRR will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations. (2) Any Federal lessee will make available upon request to the authorized ONRR or State representatives, to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm’slength sales value and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area. (3) A lessee shall notify ONRR if it has determined value pursuant to paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section. The notification shall be by letter to the Director for Office of Natural Resources Revenue of his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the form ONRR–4430 using a valuation method authorized by paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section, and each time there is a change in a method under paragraphs (c)(2)(iv) or (v) of this section. (e) If ONRR determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and PO 00000 Frm 00045 Fmt 4701 Sfmt 4700 36977 the royalty payments that are due based upon the value established by ONRR. The lessee shall also be liable for interest computed pursuant to § 1218.202 of this chapter. If the lessee is entitled to a credit, ONRR will provide instructions for the taking of that credit. (f) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to ONRR a value determination method, and may use that method in determining value for royalty purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its proposal. The ONRR shall expeditiously determine the value based upon the lessee’s proposal and any additional information ONRR deems necessary. That determination shall remain effective for the period stated therein. After ONRR issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section. (g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 1206.258 through 1206.262 and 1206.265 of this subpart. (h) The lessee is required to place coal in marketable condition at no cost to the Federal Government. Where the value established under this section is determined by a lessee’s gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition. (i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm’s-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless ONRR approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, E:\FR\FM\07AUR3.SGM 07AUR3 36978 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal. (j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by ONRR of value under this section shall be considered final or binding as against the Federal Government or its beneficiaries until the audit period is formally closed. (k) Certain information submitted to ONRR to support valuation proposals, including transportation, coal washing, or other allowances under § 1206.265 of this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. mstockstill on DSK30JT082PROD with RULES3 § 1206.258 Washing allowances—general. (a) For ad valorem leases subject to § 1206.257 of this subpart, ONRR shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 1206.257 of this subpart was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero. (b) If ONRR determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with § 1218.202 of this chapter, or shall be entitled to a credit without interest. (c) Lessees shall not disproportionately allocate washing costs to Federal leases. (d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing. (e) Coal washing costs shall only be recognized as allowances when the VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 washed coal is sold and royalties are reported and paid. § 1206.259 Determination of washing allowances. (a) Arm’s-length contracts. (1) For washing costs incurred by a lessee under an arm’s-length contract, the washing allowance shall be the reasonable actual costs incurred by the lessee for washing the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. The lessee shall have the burden of demonstrating that its contract is arm’slength. ONRR’s prior approval is not required before a lessee may deduct costs incurred under an arm’s-length contract. The lessee must claim a washing allowance by reporting it as a separate line entry on the form ONRR– 4430. (2) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then the ONRR may require that the washing allowance be determined in accordance with paragraph (b) of this section. (3) If ONRR determines that the consideration paid pursuant to an arm’slength washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the washing may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s washing costs. (4) Where the lessee’s payments for washing under an arm’s-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed. (b) Non-arm’s-length or no contract. (1) If a lessee has a non-arm’s-length contract or has no contract, including those situations where the lessee performs washing for itself, the washing allowance will be based upon the lessee’s reasonable actual costs. All washing allowances deducted under a non-arm’s-length or no contract PO 00000 Frm 00046 Fmt 4701 Sfmt 4700 situation are subject to monitoring, review, audit, and possible future adjustment. The lessee must claim a washing allowance by reporting it as a separate line entry on the form ONRR– 4430. When necessary or appropriate, ONRR may direct a lessee to modify its estimated or actual washing allowance. (2) The washing allowance for nonarm’s-length or no contract situations shall be based upon the lessee’s actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv) (A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant. (i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes, rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document. (ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document. (iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses. (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of the ONRR. (A) To compute depreciation, the lessee may elect to use either a straightline depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a wash plant shall not alter the depreciation schedule established by the original operator/ lessee for purposes of the allowance calculation. With or without a change in E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations ownership, a wash plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value. (B) ONRR shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989. (v) The rate of return must be the industrial rate associated with Standard and Poor’s BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor’s Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year. (3) The washing allowance for coal shall be determined based on the lessee’s reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing. (c) Reporting requirements—(1) Arm’s-length contracts. (i) The lessee must notify ONRR of an allowance based on incurred costs by using a separate line entry on the form ONRR– 4430. (ii) ONRR may require that a lessee submit arm’s-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR. (2) Non-arm’s-length or no contract. (i) The lessee must notify ONRR of an allowance based on the incurred costs by using a separate line entry on the form ONRR–4430. (ii) For new washing facilities or arrangements, the lessee’s initial washing deduction shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the washing system or, if such data are not available, the lessee shall use estimates based upon industry data for similar washing systems. (iii) Upon request by ONRR, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by ONRR. (d) Interest and assessments. (1) If a lessee nets a washing allowance on the form ONRR–4430, then the lessee shall be assessed an amount up to 10 percent of the allowance netted not to exceed $250 per lease sales type code per sales period. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 (2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment. (3) Interest required to be paid by this section shall be determined in accordance with § 1218.202 of this chapter. (e) Adjustments. (1) If the actual coal washing allowance is less than the amount the lessee has taken on form ONRR–4430 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under § 1218.202 of this chapter from the date when the lessee took the deduction to the date the lessee repays the difference to ONRR. If the actual washing allowance is greater than the amount the lessee has taken on form ONRR–4430 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest. (2) The lessee must submit a corrected form ONRR–4430 to reflect actual costs, together with any payment, in accordance with instructions provided by ONRR. (f) Other washing cost determinations. The provisions of this section shall apply to determine washing costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of washing costs. § 1206.260 Allocation of washed coal. (a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted. (b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant. (c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed. § 1206.261 general. Transportation allowances— (a) For ad valorem leases subject to § 1206.257 of this subpart, where the value for royalty purposes has been determined at a point remote from the lease or mine, ONRR shall, as authorized by this section, allow a PO 00000 Frm 00047 Fmt 4701 Sfmt 4700 36979 deduction in determining value for royalty purposes for the reasonable, actual costs incurred to: (1) Transport the coal from a Federal lease to a sales point which is remote from both the lease and mine; or (2) Transport the coal from a Federal lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance. (b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero. (c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported. (2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported. (3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid. (d) If, after a review and/or audit, ONRR determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with § 1218.202 of this chapter, or shall be entitled to a credit, without interest. (e) Lessees shall not disproportionately allocate transportation costs to Federal leases. § 1206.262 Determination of transportation allowances. (a) Arm’s-length contracts. (1) For transportation costs incurred by a lessee pursuant to an arm’s-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. The lessee shall have the burden of demonstrating that its contract is arm’s-length. The lessee must claim a transportation allowance by E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36980 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations reporting it as a separate line entry on the form ONRR–4430. (2) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then the ONRR may require that the transportation allowance be determined in accordance with paragraph (b) of this section. (3) If ONRR determines that the consideration paid pursuant to an arm’slength transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the transportation may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s transportation costs. (4) Where the lessee’s payments for transportation under an arm’s-length contract are not based on a dollar-perunit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section. (b) Non-arm’s-length or no contract— (1) If a lessee has a non-arm’s-length contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee’s reasonable actual costs. All transportation allowances deducted under a non-arm’slength or no contract situation are subject to monitoring, review, audit, and possible future adjustment. The lessee must claim a transportation allowance by reporting it as a separate line entry on the form ONRR–4430. When necessary or appropriate, ONRR may direct a lessee to modify its estimated or actual transportation allowance deduction. (2) The transportation allowance for non-arm’s-length or no-contract situations shall be based upon the lessee’s actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system. (i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document. (ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document. (iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses. (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of ONRR. (A) To compute depreciation, the lessee may elect to use either a straightline depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value. (B) ONRR shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(B)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989. (v) The rate of return must be the industrial rate associated with Standard PO 00000 Frm 00048 Fmt 4701 Sfmt 4700 and Poor’s BBB rating. The rate of return must be the monthly average rate as published in Standard and Poor’s Bond Guide for the first month for which the allowance is applicable. The rate must be redetermined at the beginning of each subsequent calendar year. (3) A lessee may apply to ONRR for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (2) of this section. ONRR will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency or by a State regulatory agency (for Federal leases). ONRR shall deny the exception request if it determines that the rate is excessive as compared to arm’s-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm’s-length transportation charges, ONRR shall deny the exception request if: (i) No Federal or State regulatory agency costs analysis exists and the Federal or State regulatory agency, as applicable, has declined to investigate under ONRR timely objections upon filing; and (ii) The rate significantly exceeds the lessee’s actual costs for transportation as determined under this section. (c) Reporting requirements—(1) Arm’s-length contracts. (i) The lessee must notify ONRR of an allowance based on incurred costs by using a separate line entry on the form ONRR– 4430. (ii) ONRR may require that a lessee submit arm’s-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR. (2) Non-arm’s-length or no contract— (i) The lessee must notify ONRR of an allowance based on the incurred costs by using a separate line entry on form ONRR–4430. (ii) For new transportation facilities or arrangements, the lessee’s initial deduction shall include estimates of the allowable coal transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems. (iii) Upon request by ONRR, the lessee shall submit all data used to prepare the allowance deduction. The data shall be provided within a reasonable period of time, as determined by ONRR. E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (iv) If the lessee is authorized to use its Federal- or State-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section. (d) Interest and assessments. (1) If a lessee nets a transportation allowance on form ONRR–4430, the lessee shall be assessed an amount of up to 10 percent of the allowance netted not to exceed $250 per lease sales type code per sales period. (2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment. (3) Interest required to be paid by this section shall be determined in accordance with § 1218.202 of this chapter. (e) Adjustments. (1) If the actual coal transportation allowance is less than the amount the lessee has taken on form ONRR–4430 for each month during the allowance reporting period, the lessee shall pay additional royalties due plus interest computed under § 1218.202 of this chapter from the date when the lessee took the deduction to the date the lessee repays the difference to ONRR. If the actual transportation allowance is greater than amount the lessee has taken on form ONRR–4430 for each month during the allowance reporting period, the lessee shall be entitled to a credit without interest. (2) The lessee must submit a corrected form ONRR–4430 to reflect actual costs, together with any payments, in accordance with instructions provided by ONRR. (f) Other transportation cost determinations. The provisions of this section shall apply to determine transportation costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of transportation costs. § 1206.263 [Reserved] § 1206.265 Value enhancement of marketable coal. If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in accordance with § 1206.257(h) of this subpart, the lessee shall notify ONRR that such processing is occurring or will occur. The value of that production shall be determined as follows: (a) A value established for the feedstock coal in marketable condition by application of the provisions of § 1206.257(c)(2)(i) through (iv) of this subpart; or, (b) In the event that a value cannot be established in accordance with paragraph (a) of this section, then the value of production will be determined in accordance with § 1206.257(c)(2)(v) of this subpart and the value shall be the lessee’s gross proceeds accruing from the disposition of the enhanced product, reduced by ONRR-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor’s BBB bond rate applicable under § 1206.259(b)(2)(v) of this subpart. ■ 9. Revise subpart J to read as follows: Subpart J—Indian Coal Sec. 1206.450 Purpose and scope. 1206.451 Definitions. 1206.452 Coal subject to royalties—general provisions. 1206.453 Quality and quantity measurement standards for reporting and paying royalties. 1206.454 Point of royalty determination. 1206.455 Valuation standards for cents-perton leases. 1206.456 Valuation standards for ad valorem leases. 1206.457 Washing allowances—general. 1206.458 Determination of washing allowances. 1206.459 Allocation of washed coal. 1206.460 Transportation allowances— general. 1206.461 Determination of transportation allowances. 1206.462 [Reserved] 1206.463 In-situ and surface gasification and liquefaction operations. 1206.464 Value enhancement of marketable coal. mstockstill on DSK30JT082PROD with RULES3 § 1206.264 In-situ and surface gasification and liquefaction operations. Subpart J—Indian Coal If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to ONRR. The ONRR will review the lessee’s proposal and issue a value determination. The lessee may use its proposed value until ONRR issues a value determination. (a) This subpart prescribes the procedures to establish the value, for royalty purposes, of all coal from Indian Tribal and allotted leases (except leases on the Osage Indian Reservation, Osage County, Oklahoma). (b) If the specific provisions of any statute, treaty, or settlement agreement between the Indian lessor and a lessee VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 § 1206.450 PO 00000 Purpose and scope. Frm 00049 Fmt 4701 Sfmt 4700 36981 resulting from administrative or judicial litigation, or any coal lease subject to the requirements of this subpart, are inconsistent with any regulation in this subpart, then the statute, treaty, lease provision, or settlement shall govern to the extent of that inconsistency. (c) All royalty payments are subject to later audit and adjustment. (d) The regulations in this subpart are intended to ensure that the trust responsibilities of the United States with respect to the administration of Indian coal leases are discharged in accordance with the requirements of the governing mineral leasing laws, treaties, and lease terms. § 1206.451 Definitions. Ad valorem lease means a lease where the royalty due to the lessor is based upon a percentage of the amount or value of the coal. Allowance means an approved, or an ONRR-initially accepted deduction in determining value for royalty purposes. Coal washing allowance means an allowance for the reasonable, actual costs incurred by the lessee for coal washing, or an approved or ONRRinitially accepted deduction for the costs of washing coal, determined pursuant to this subpart. Transportation allowance means an allowance for the reasonable, actual costs incurred by the lessee for moving coal to a point of sale or point of delivery remote from both the lease and mine or wash plant, or an approved ONRR-initially accepted deduction for costs of such transportation, determined pursuant to this subpart. Area means a geographic region in which coal has similar quality and economic characteristics. Area boundaries are not officially designated and the areas are not necessarily named. Arm’s-length contract means a contract or agreement that has been arrived at in the marketplace between independent, nonaffiliated persons with opposing economic interests regarding that contract. For purposes of this subpart, two persons are affiliated if one person controls, is controlled by, or is under common control with another person. For purposes of this subpart, based on the instruments of ownership of the voting securities of an entity, or based on other forms of ownership: Ownership in excess of 50 percent constitutes control; ownership of 10 through 50 percent creates a presumption of control; and ownership of less than 10 percent creates a presumption of noncontrol which ONRR may rebut if it demonstrates actual or legal control, including the existence of interlocking directorates. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36982 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations Notwithstanding any other provisions of this subpart, contracts between relatives, either by blood or by marriage, are not arm’s-length contracts. ONRR may require the lessee to certify ownership control. To be considered arm’s-length for any production month, a contract must meet the requirements of this definition for that production month, as well as when the contract was executed. Audit means a review, conducted in accordance with generally accepted accounting and auditing standards, of royalty payment compliance activities of lessees or other interest holders who pay royalties, rents, or bonuses on Indian leases. BIA means the Bureau of Indian Affairs of the Department of the Interior. BLM means the Bureau of Land Management of the Department of the Interior. Coal means coal of all ranks from lignite through anthracite. Coal washing means any treatment to remove impurities from coal. Coal washing may include, but is not limited to, operations such as flotation, air, water, or heavy media separation; drying; and related handling (or combination thereof). Contract means any oral or written agreement, including amendments or revisions thereto, between two or more persons and enforceable by law that with due consideration creates an obligation. Gross proceeds (for royalty payment purposes) means the total monies and other consideration accruing to a coal lessee for the production and disposition of the coal produced. Gross proceeds includes, but is not limited to, payments to the lessee for certain services such as crushing, sizing, screening, storing, mixing, loading, treatment with substances including chemicals or oils, and other preparation of the coal to the extent that the lessee is obligated to perform them at no cost to the Indian lessor. Gross proceeds, as applied to coal, also includes but is not limited to reimbursements for royalties, taxes or fees, and other reimbursements. Tax reimbursements are part of the gross proceeds accruing to a lessee even though the Indian royalty interest may be exempt from taxation. Monies and other consideration, including the forms of consideration identified in this paragraph, to which a lessee is contractually or legally entitled but which it does not seek to collect through reasonable efforts are also part of gross proceeds. Indian allottee means any Indian for whom land or an interest in land is held in trust by the United States or who VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 holds title subject to Federal restriction against alienation. Indian Tribe means any Indian Tribe, band, nation, pueblo, community, rancheria, colony, or other group of Indians for which any land or interest in land is held in trust by the United States or which is subject to Federal restriction against alienation. Lease means any contract, profit-share arrangement, joint venture, or other agreement issued or approved by the United States for an Indian coal resource under a mineral leasing law that authorizes exploration for, development or extraction of, or removal of coal—or the land covered by that authorization, whichever is required by the context. Lessee means any person to whom the Indian Tribe or an Indian allottee issues a lease, and any person who has been assigned an obligation to make royalty or other payments required by the lease. This includes any person who has an interest in a lease as well as an operator or payor who has no interest in the lease but who has assumed the royalty payment responsibility. Like-quality coal means coal that has similar chemical and physical characteristics. Marketable condition means coal that is sufficiently free from impurities and otherwise in a condition that it will be accepted by a purchaser under a sales contract typical for that area. Mine means an underground or surface excavation or series of excavations and the surface or underground support facilities that contribute directly or indirectly to mining, production, preparation, and handling of lease products. Net-back method means a method for calculating market value of coal at the lease or mine. Under this method, costs of transportation, washing, handling, etc., are deducted from the ultimate proceeds received for the coal at the first point at which reasonable values for the coal may be determined by a sale pursuant to an arm’s-length contract or by comparison to other sales of coal, to ascertain value at the mine. Net output means the quantity of washed coal that a washing plant produces. ONRR means the Office of Natural Resources Revenue of the Department of the Interior. Person means by individual, firm, corporation, association, partnership, consortium, or joint venture. Sales type code means the contract type or general disposition (e.g., arm’slength or non-arm’s-length) of production from the lease. The sales type code applies to the sales contract, PO 00000 Frm 00050 Fmt 4701 Sfmt 4700 or other disposition, and not to the arm’s-length or non-arm’s-length nature of a transportation or washing allowance. Spot market price means the price received under any sales transaction when planned or actual deliveries span a short period of time, usually not exceeding one year. § 1206.452 Coal subject to royalties— general provisions. (a) All coal (except coal unavoidably lost as determined by BLM pursuant to 43 CFR group 3400) from an Indian lease subject to this part is subject to royalty. This includes coal used, sold, or otherwise disposed of by the lessee on or off the lease. (b) If a lessee receives compensation for unavoidably lost coal through insurance coverage or other arrangements, royalties at the rate specified in the lease are to be paid on the amount of compensation received for the coal. No royalty is due on insurance compensation received by the lessee for other losses. (c) If waste piles or slurry ponds are reworked to recover coal, the lessee shall pay royalty at the rate specified in the lease at the time the recovered coal is used, sold, or otherwise finally disposed of. The royalty rate shall be that rate applicable to the production method used to initially mine coal in the waste pile or slurry pond; i.e., underground mining method or surface mining method. Coal in waste pits or slurry ponds initially mined from Indian leases shall be allocated to such leases regardless of whether it is stored on Indian lands. The lessee shall maintain accurate records to determine to which individual Indian lease coal in the waste pit or slurry pond should be allocated. However, nothing in this section requires payment of a royalty on coal for which a royalty has already been paid. § 1206.453 Quality and quantity measurement standards for reporting and paying royalties. For all leases subject to this subpart, the quantity of coal on which royalty is due shall be measured in short tons (of 2,000 pounds each) by methods prescribed by the BLM. Coal quantity information will be reported on appropriate forms required under 30 CFR part 1210—Forms and Reports. § 1206.454 Point of royalty determination. (a) For all leases subject to this subpart, royalty shall be computed on the basis of the quantity and quality of Indian coal in marketable condition measured at the point of royalty E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations measurement as determined jointly by BLM and ONRR. (b) Coal produced and added to stockpiles or inventory does not require payment of royalty until such coal is later used, sold, or otherwise finally disposed of. ONRR may ask BLM or BIA to increase the lease bond to protect the lessor’s interest when BLM determines that stockpiles or inventory become excessive so as to increase the risk of degradation of the resource. (c) The lessee shall pay royalty at a rate specified in the lease at the time the coal is used, sold, or otherwise finally disposed of, unless otherwise provided for at § 1206.455(d) of this subpart. § 1206.455 Valuation standards for centsper-ton leases. (a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty on a cents-perton (or other quantity) basis. (b) The royalty for coal from leases subject to this section shall be based on the dollar rate per ton prescribed in the lease. That dollar rate shall be applicable to the actual quantity of coal used, sold, or otherwise finally disposed of, including coal which is avoidably lost as determined by BLM pursuant to 43 CFR part 3400. (c) For leases subject to this section, there shall be no allowances for transportation, removal of impurities, coal washing, or any other processing or preparation of the coal. (d) When a coal lease is readjusted pursuant to 43 CFR part 3400 and the royalty valuation method changes from a cents-per-ton basis to an ad valorem basis, coal which is produced prior to the effective date of readjustment and sold or used within 30 days of the effective date of readjustment shall be valued pursuant to this section. All coal that is not used, sold, or otherwise finally disposed of within 30 days after the effective date of readjustment shall be valued pursuant to the provisions of § 1206.456 of this subpart, and royalties shall be paid at the royalty rate specified in the readjusted lease. mstockstill on DSK30JT082PROD with RULES3 § 1206.456 Valuation standards for ad valorem leases. (a) This section is applicable to coal leases on Indian Tribal and allotted Indian lands (except leases on the Osage Indian Reservation, Osage County, Oklahoma) which provide for the determination of royalty as a percentage of the amount of value of coal (ad valorem). The value for royalty purposes of coal from such leases shall be the VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 value of coal determined pursuant to this section, less applicable coal washing allowances and transportation allowances determined pursuant to §§ 1206.457 through 1206.461 of this subpart, or any allowance authorized by § 1206.464 of this subpart. The royalty due shall be equal to the value for royalty purposes multiplied by the royalty rate in the lease. (b)(1) The value of coal that is sold pursuant to an arm’s-length contract shall be the gross proceeds accruing to the lessee, except as provided in paragraphs (b)(2), (3), and (5) of this section. The lessee shall have the burden of demonstrating that its contract is arm’s-length. The value which the lessee reports, for royalty purposes, is subject to monitoring, review, and audit. (2) In conducting reviews and audits, ONRR will examine whether the contract reflects the total consideration actually transferred either directly or indirectly from the buyer to the seller for the coal produced. If the contract does not reflect the total consideration, then ONRR may require that the coal sold pursuant to that contract be valued in accordance with paragraph (c) of this section. Value may not be based on less than the gross proceeds accruing to the lessee for the coal production, including the additional consideration. (3) If ONRR determines that the gross proceeds accruing to the lessee pursuant to an arm’s-length contract do not reflect the reasonable value of the production because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the coal production be valued pursuant to paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section, and in accordance with the notification requirements of paragraph (d)(3) of this section. When ONRR determines that the value may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s reported coal value. (4) ONRR may require a lessee to certify that its arm’s-length contract provisions include all of the consideration to be paid by the buyer, either directly or indirectly, for the coal production. (5) The value of production for royalty purposes shall not include payments received by the lessee pursuant to a contract which the lessee demonstrates, to ONRR’s satisfaction, were not part of the total consideration paid for the purchase of coal production. PO 00000 Frm 00051 Fmt 4701 Sfmt 4700 36983 (c)(1) The value of coal from leases subject to this section and which is not sold pursuant to an arm’s-length contract shall be determined in accordance with this section. (2) If the value of the coal cannot be determined pursuant to paragraph (b) of this section, then the value shall be determined through application of other valuation criteria. The criteria shall be considered in the following order, and the value shall be based upon the first applicable criterion: (i) The gross proceeds accruing to the lessee pursuant to a sale under its nonarm’s-length contract (or other disposition of produced coal by other than an arm’s-length contract), provided that those gross proceeds are within the range of the gross proceeds derived from, or paid under, comparable arm’slength contracts between buyers and sellers neither of whom is affiliated with the lessee for sales, purchases, or other dispositions of like-quality coal produced in the area. In evaluating the comparability of arm’s-length contracts for the purposes of these regulations, the following factors shall be considered: Price, time of execution, duration, market or markets served, terms, quality of coal, quantity, and such other factors as may be appropriate to reflect the value of the coal; (ii) Prices reported for that coal to a public utility commission; (iii) Prices reported for that coal to the Energy Information Administration of the Department of Energy; (iv) Other relevant matters including, but not limited to, published or publicly available spot market prices, or information submitted by the lessee concerning circumstances unique to a particular lease operation or the salability of certain types of coal; (v) If a reasonable value cannot be determined using paragraphs (c)(2)(i), (ii), (iii), or (iv) of this section, then a net-back method or any other reasonable method shall be used to determine value. (3) When the value of coal is determined pursuant to paragraph (c)(2) of this section, that value determination shall be consistent with the provisions contained in paragraph (b)(5) of this section. (d)(1) Where the value is determined pursuant to paragraph (c) of this section, that value does not require ONRR’s prior approval. However, the lessee shall retain all data relevant to the determination of royalty value. Such data shall be subject to review and audit, and ONRR will direct a lessee to use a different value if it determines that the reported value is inconsistent with the requirements of these regulations. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36984 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (2) An Indian lessee will make available upon request to the authorized ONRR or Indian representatives, or to the Inspector General of the Department of the Interior or other persons authorized to receive such information, arm’s-length sales and sales quantity data for like-quality coal sold, purchased, or otherwise obtained by the lessee from the area. (3) A lessee shall notify ONRR if it has determined value pursuant to paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section. The notification shall be by letter to the Director for Office of Natural Resources Revenue or his/her designee. The letter shall identify the valuation method to be used and contain a brief description of the procedure to be followed. The notification required by this section is a one-time notification due no later than the month the lessee first reports royalties on the form ONRR–4430 using a valuation method authorized by paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section, and each time there is a change in a method under paragraphs (c)(2)(iv) or (v) of this section. (e) If ONRR determines that a lessee has not properly determined value, the lessee shall be liable for the difference, if any, between royalty payments made based upon the value it has used and the royalty payments that are due based upon the value established by ONRR. The lessee shall also be liable for interest computed pursuant to 30 CFR 1218.202. If the lessee is entitled to a credit, ONRR will provide instructions for the taking of that credit. (f) The lessee may request a value determination from ONRR. In that event, the lessee shall propose to ONRR a value determination method, and may use that method in determining value for royalty purposes until ONRR issues its decision. The lessee shall submit all available data relevant to its proposal. ONRR shall expeditiously determine the value based upon the lessee’s proposal and any additional information ONRR deems necessary. That determination shall remain effective for the period stated therein. After ONRR issues its determination, the lessee shall make the adjustments in accordance with paragraph (e) of this section. (g) Notwithstanding any other provisions of this section, under no circumstances shall the value for royalty purposes be less than the gross proceeds accruing to the lessee for the disposition of produced coal less applicable provisions of paragraph (b)(5) of this section and less applicable allowances determined pursuant to §§ 1206.457 through 1206.461 and 1206.464 of this subpart. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 (h) The lessee is required to place coal in marketable condition at no cost to the Indian lessor. Where the value established pursuant to this section is determined by a lessee’s gross proceeds, that value shall be increased to the extent that the gross proceeds has been reduced because the purchaser, or any other person, is providing certain services, the cost of which ordinarily is the responsibility of the lessee to place the coal in marketable condition. (i) Value shall be based on the highest price a prudent lessee can receive through legally enforceable claims under its contract. Absent contract revision or amendment, if the lessee fails to take proper or timely action to receive prices or benefits to which it is entitled, it must pay royalty at a value based upon that obtainable price or benefit. Contract revisions or amendments shall be in writing and signed by all parties to an arm’s-length contract, and may be retroactively applied to value for royalty purposes for a period not to exceed two years, unless ONRR approves a longer period. If the lessee makes timely application for a price increase allowed under its contract but the purchaser refuses, and the lessee takes reasonable measures, which are documented, to force purchaser compliance, the lessee will owe no additional royalties unless or until monies or consideration resulting from the price increase are received. This paragraph shall not be construed to permit a lessee to avoid its royalty payment obligation in situations where a purchaser fails to pay, in whole or in part or timely, for a quantity of coal. (j) Notwithstanding any provision in these regulations to the contrary, no review, reconciliation, monitoring, or other like process that results in a redetermination by ONRR of value under this section shall be considered final or binding as against the Indian Tribes or allottees until the audit period is formally closed. (k) Certain information submitted to ONRR to support valuation proposals, including transportation, coal washing, or other allowances pursuant to §§ 1206.457 through 1206.461 and 1206.464 of this subpart, is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data specified by the Act to be privileged, confidential, or otherwise exempt shall be maintained in a confidential manner in accordance with applicable law and regulations. All requests for information about determinations made under this part are to be submitted in accordance with the Freedom of Information Act regulation of the Department of the Interior, 43 CFR part 2. Nothing in this PO 00000 Frm 00052 Fmt 4701 Sfmt 4700 section is intended to limit or diminish in any manner whatsoever the right of an Indian lessor to obtain any and all information as such lessor may be lawfully entitled from ONRR or such lessor’s lessee directly under the terms of the lease or applicable law. § 1206.457 Washing allowances—general. (a) For ad valorem leases subject to § 1206.456 of this subpart, ONRR shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to wash coal, unless the value determined pursuant to § 1206.456 of this subpart was based upon like-quality unwashed coal. Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero. (b) If ONRR determines that a lessee has improperly determined a washing allowance authorized by this section, then the lessee shall be liable for any additional royalties, plus interest determined in accordance with § 1218.202 of this chapter, or shall be entitled to a credit, without interest. (c) Lessees shall not disproportionately allocate washing costs to Indian leases. (d) No cost normally associated with mining operations and which are necessary for placing coal in marketable condition shall be allowed as a cost of washing. (e) Coal washing costs shall only be recognized as allowances when the washed coal is sold and royalties are reported and paid. § 1206.458 Determination of washing allowances. (a) Arm’s-length contracts. (1) For washing costs incurred by a lessee pursuant to an arm’s-length contract, the washing allowance shall be the reasonable actual costs incurred by the lessee for washing the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. ONRR’s prior approval is not required before a lessee may deduct costs incurred under an arm’s-length contract. However, before any deduction may be taken, the lessee must submit a completed page one of form ONRR– 4292, Coal Washing Allowance Report, in accordance with paragraph (c)(1) of this section. A washing allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that form ONRR–4292 is filed with ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (2) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the washer for the washing. If the contract reflects more than the total consideration paid, then ONRR may require that the washing allowance be determined in accordance with paragraph (b) of this section. (3) If ONRR determines that the consideration paid pursuant to an arm’slength washing contract does not reflect the reasonable value of the washing because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the washing allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the washing may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s washing costs. (4) Where the lessee’s payments for washing under an arm’s-length contract are not based on a dollar-per-unit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent. Washing allowances shall be expressed as a cost per ton of coal washed. (b) Non-arm’s-length or no contract. (1) If a lessee has a non-arm’s-length contract or has no contract, including those situations where the lessee performs washing for itself, the washing allowance will be based upon the lessee’s reasonable actual costs. All washing allowances deducted under a non-arm’s-length or no contract situation are subject to monitoring, review, audit, and possible future adjustment. Prior ONRR approval of washing allowances is not required for non-arm’s-length or no contract situations. However, before any estimated or actual deduction may be taken, the lessee must submit a completed form ONRR–4292 in accordance with paragraph (c)(2) of this section. A washing allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that form ONRR–4292 is filed with ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee. ONRR will monitor the allowance deduction to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR may VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 direct a lessee to modify its actual washing allowance. (2) The washing allowance for nonarm’s-length or no contract situations shall be based upon the lessee’s actual costs for washing during the reported period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or a cost equal to the depreciable investment in the wash plant multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the wash plant. (i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document. (ii) Allowable maintenance expenses include: Maintenance of the wash plant; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document. (iii) Overhead attributable and allocable to the operation and maintenance of the wash plant is an allowable expense. State and Federal income taxes and severance taxes, including royalties, are not allowable expenses. (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a wash plant, the lessee may not later elect to change to the other alternative without approval of ONRR. (A) To compute depreciation, the lessee may elect to use either a straightline depreciation method based on the life of equipment or on the life of the reserves which the wash plant services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a wash plant shall not alter the depreciation schedule established by the original operator/ lessee for purposes of the allowance calculation. With or without a change in ownership, a wash plant shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value. (B) ONRR shall allow as a cost an amount equal to the allowable capital investment in the wash plant multiplied PO 00000 Frm 00053 Fmt 4701 Sfmt 4700 36985 by the rate of return determined pursuant to paragraph (b)(2)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to plants first placed in service or acquired after March 1, 1989. (v) The rate of return shall be the industrial rate associated with Standard and Poor’s BBB rating. The rate of return shall be the monthly average rate as published in Standard and Poor’s Bond Guide for the first month of the reporting period for which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent washing allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section). (3) The washing allowance for coal shall be determined based on the lessee’s reasonable and actual cost of washing the coal. The lessee may not take an allowance for the costs of washing lease production that is not royalty bearing. (c) Reporting requirements—(1) Arm’s-length contracts. (i) With the exception of those washing allowances specified in paragraphs (c)(1)(v) and (vi) of this section, the lessee shall submit page one of the initial form ONRR–4292 prior to, or at the same time, as the washing allowance determined pursuant to an arm’s-length contract is reported on form ONRR–4430, Solid Minerals Production and Royalty Report. A form ONRR–4292 received by the end of the month that the form ONRR–4430 is due shall be considered to be received timely. (ii) The initial form ONRR–4292 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier. (iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of form ONRR–4292 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless ONRR approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period). (iv) ONRR may require that a lessee submit arm’s-length washing contracts and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR. (v) Washing allowances which are based on arm’s-length contracts and E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36986 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by ONRR in writing shall qualify as being in effect at the time these regulations become effective. (vi) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section. (2) Non-arm’s-length or no contract. (i) With the exception of those washing allowances specified in paragraphs (c)(2)(v) and (vii) of this section, the lessee shall submit an initial form ONRR–4292 prior to, or at the same time as, the washing allowance determined pursuant to a non-arm’s-length contract or no contract situation is reported on form ONRR–4430, Solid Minerals Production and Royalty Report. A form ONRR–4292 received by the end of the month that the form ONRR–4430 is due shall be considered to be timely received. The initial reporting may be based on estimated costs. (ii) The initial form ONRR–4292 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a washing allowance and shall continue until the end of the calendar year, or until the washing under the non-arm’s-length contract or the no contract situation terminates, whichever is earlier. (iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed form ONRR–4292 containing the actual costs for the previous reporting period. If coal washing is continuing, the lessee shall include on form ONRR–4292 its estimated costs for the next calendar year. The estimated coal washing allowance shall be based on the actual costs for the previous period plus or minus any adjustments which are based on the lessee’s knowledge of decreases or increases which will affect the allowance. Form ONRR–4292 must be received by ONRR within 3 months after the end of the previous reporting period, unless ONRR approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period). (iv) For new wash plants, the lessee’s initial form ONRR–4292 shall include estimates of the allowable coal washing costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the plant, or if such data are not available, the lessee shall use estimates VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 based upon industry data for similar coal wash plants. (v) Washing allowances based on nonarm’s-length or no contract situations which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by ONRR in writing shall qualify as being in effect at the time these regulations become effective. (vi) Upon request by ONRR, the lessee shall submit all data used by the lessee to prepare its forms ONRR–4292. The data shall be provided within a reasonable period of time, as determined by ONRR. (vii) ONRR may establish, in appropriate circumstances, reporting requirements which are different from the requirements of this section. (3) ONRR may establish coal washing allowance reporting dates for individual leases different from those specified in this subpart in order to provide more effective administration. Lessees will be notified of any change in their reporting period. (4) Washing allowances must be reported as a separate line on the form ONRR–4430, unless ONRR approves a different reporting procedure. (d) Interest assessments for incorrect or late reports and failure to report. (1) If a lessee deducts a washing allowance on its form ONRR–4430 without complying with the requirements of this section, the lessee shall be liable for interest on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section. (2) If a lessee erroneously reports a washing allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment. (3) Interest required to be paid by this section shall be determined in accordance with § 1218.202 of this chapter. (e) Adjustments. (1) If the actual coal washing allowance is less than the amount the lessee has taken on form ONRR–4430 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest computed pursuant to § 1218.202, retroactive to the first month the lessee is authorized to deduct a washing allowance. If the actual washing allowance is greater than the amount the lessee has estimated and taken during PO 00000 Frm 00054 Fmt 4701 Sfmt 4700 the reporting period, the lessee shall be entitled to a credit, without interest. (2) The lessee must submit a corrected form ONRR–4430 to reflect actual costs, together with any payment, in accordance with instructions provided by ONRR. (f) Other washing cost determinations. The provisions of this section shall apply to determine washing costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of washing costs. § 1206.459 Allocation of washed coal. (a) When coal is subjected to washing, the washed coal must be allocated to the leases from which it was extracted. (b) When the net output of coal from a washing plant is derived from coal obtained from only one lease, the quantity of washed coal allocable to the lease will be based on the net output of the washing plant. (c) When the net output of coal from a washing plant is derived from coal obtained from more than one lease, unless determined otherwise by BLM, the quantity of net output of washed coal allocable to each lease will be based on the ratio of measured quantities of coal delivered to the washing plant and washed from each lease compared to the total measured quantities of coal delivered to the washing plant and washed. § 1206.460 general. Transportation allowances— (a) For ad valorem leases subject to § 1206.456 of this subpart, where the value for royalty purposes has been determined at a point remote from the lease or mine, ONRR shall, as authorized by this section, allow a deduction in determining value for royalty purposes for the reasonable, actual costs incurred to: (1) Transport the coal from an Indian lease to a sales point which is remote from both the lease and mine; or (2) Transport the coal from an Indian lease to a wash plant when that plant is remote from both the lease and mine and, if applicable, from the wash plant to a remote sales point. In-mine transportation costs shall not be included in the transportation allowance. (b) Under no circumstances will the authorized washing allowance and the transportation allowance reduce the value for royalty purposes to zero. (c)(1) When coal transported from a mine to a wash plant is eligible for a transportation allowance in accordance with this section, the lessee is not required to allocate transportation costs E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations between the quantity of clean coal output and the rejected waste material. The transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of cleaned coal transported. (2) For coal that is not washed at a wash plant, the transportation allowance shall be authorized for the total production which is transported. Transportation allowances shall be expressed as a cost per ton of coal transported. (3) Transportation costs shall only be recognized as allowances when the transported coal is sold and royalties are reported and paid. (d) If, after a review and/or audit, ONRR determines that a lessee has improperly determined a transportation allowance authorized by this section, then the lessee shall pay any additional royalties, plus interest, determined in accordance with § 1218.202 of this chapter, or shall be entitled to a credit, without interest. (e) Lessees shall not disproportionately allocate transportation costs to Indian leases. mstockstill on DSK30JT082PROD with RULES3 § 1206.461 Determination of transportation allowances. (a) Arm’s-length contracts. (1) For transportation costs incurred by a lessee pursuant to an arm’s-length contract, the transportation allowance shall be the reasonable, actual costs incurred by the lessee for transporting the coal under that contract, subject to monitoring, review, audit, and possible future adjustment. ONRR’s prior approval is not required before a lessee may deduct costs incurred under an arm’s-length contract. However, before any deduction may be taken, the lessee must submit a completed page one of form ONRR– 4293, Coal Transportation Allowance Report, in accordance with paragraph (c)(1) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that form ONRR–4293 is filed with ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee. (2) In conducting reviews and audits, ONRR will examine whether the contract reflects more than the consideration actually transferred either directly or indirectly from the lessee to the transporter for the transportation. If the contract reflects more than the total consideration paid, then ONRR may require that the transportation allowance be determined in accordance with paragraph (b) of this section. VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 (3) If ONRR determines that the consideration paid pursuant to an arm’slength transportation contract does not reflect the reasonable value of the transportation because of misconduct by or between the contracting parties, or because the lessee otherwise has breached its duty to the lessor to market the production for the mutual benefit of the lessee and the lessor, then ONRR shall require that the transportation allowance be determined in accordance with paragraph (b) of this section. When ONRR determines that the value of the transportation may be unreasonable, ONRR will notify the lessee and give the lessee an opportunity to provide written information justifying the lessee’s transportation costs. (4) Where the lessee’s payments for transportation under an arm’s-length contract are not based on a dollar-perunit basis, the lessee shall convert whatever consideration is paid to a dollar value equivalent for the purposes of this section. (b) Non-arm’s-length or no contract. (1) If a lessee has a non-arm’s-length contract or has no contract, including those situations where the lessee performs transportation services for itself, the transportation allowance will be based upon the lessee’s reasonable actual costs. All transportation allowances deducted under a non-arm’slength or no contract situation are subject to monitoring, review, audit, and possible future adjustment. Prior ONRR approval of transportation allowances is not required for non-arm’s-length or no contract situations. However, before any estimated or actual deduction may be taken, the lessee must submit a completed form ONRR–4293 in accordance with paragraph (c)(2) of this section. A transportation allowance may be claimed retroactively for a period of not more than 3 months prior to the first day of the month that form ONRR–4293 is filed with ONRR, unless ONRR approves a longer period upon a showing of good cause by the lessee. ONRR will monitor the allowance deductions to ensure that deductions are reasonable and allowable. When necessary or appropriate, ONRR may direct a lessee to modify its estimated or actual transportation allowance deduction. (2) The transportation allowance for non-arm’s-length or no contract situations shall be based upon the lessee’s actual costs for transportation during the reporting period, including operating and maintenance expenses, overhead, and either depreciation and a return on undepreciated capital investment in accordance with paragraph (b)(2)(iv)(A) of this section, or PO 00000 Frm 00055 Fmt 4701 Sfmt 4700 36987 a cost equal to the depreciable investment in the transportation system multiplied by the rate of return in accordance with paragraph (b)(2)(iv)(B) of this section. Allowable capital costs are generally those for depreciable fixed assets (including costs of delivery and installation of capital equipment) which are an integral part of the transportation system. (i) Allowable operating expenses include: Operations supervision and engineering; operations labor; fuel; utilities; materials; ad valorem property taxes; rent; supplies; and any other directly allocable and attributable operating expense which the lessee can document. (ii) Allowable maintenance expenses include: Maintenance of the transportation system; maintenance of equipment; maintenance labor; and other directly allocable and attributable maintenance expenses which the lessee can document. (iii) Overhead attributable and allocable to the operation and maintenance of the transportation system is an allowable expense. State and Federal income taxes and severance taxes and other fees, including royalties, are not allowable expenses. (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this section. After a lessee has elected to use either method for a transportation system, the lessee may not later elect to change to the other alternative without approval of ONRR. (A) To compute depreciation, the lessee may elect to use either a straightline depreciation method based on the life of equipment or on the life of the reserves which the transportation system services, whichever is appropriate, or a unit of production method. After an election is made, the lessee may not change methods without ONRR approval. A change in ownership of a transportation system shall not alter the depreciation schedule established by the original transporter/lessee for purposes of the allowance calculation. With or without a change in ownership, a transportation system shall be depreciated only once. Equipment shall not be depreciated below a reasonable salvage value. (B) ONRR shall allow as a cost an amount equal to the allowable capital investment in the transportation system multiplied by the rate of return determined pursuant to paragraph (b)(2)(B)(v) of this section. No allowance shall be provided for depreciation. This alternative shall apply only to transportation facilities first placed in service or acquired after March 1, 1989. E:\FR\FM\07AUR3.SGM 07AUR3 mstockstill on DSK30JT082PROD with RULES3 36988 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations (v) The rate of return shall be the industrial rate associated with Standard and Poor’s BBB rating. The rate of return shall be the monthly average as published in Standard and Poor’s Bond Guide for the first month of the reporting period of which the allowance is applicable and shall be effective during the reporting period. The rate shall be redetermined at the beginning of each subsequent transportation allowance reporting period (which is determined pursuant to paragraph (c)(2) of this section). (3) A lessee may apply to ONRR for exception from the requirement that it compute actual costs in accordance with paragraphs (b)(1) and (2) of this section. ONRR will grant the exception only if the lessee has a rate for the transportation approved by a Federal agency for Indian leases. ONRR shall deny the exception request if it determines that the rate is excessive as compared to arm’s-length transportation charges by systems, owned by the lessee or others, providing similar transportation services in that area. If there are no arm’s-length transportation charges, ONRR shall deny the exception request if: (i) No Federal regulatory agency cost analysis exists and the Federal regulatory agency has declined to investigate pursuant to ONRR timely objections upon filing; and (ii) The rate significantly exceeds the lessee’s actual costs for transportation as determined under this section. (c) Reporting requirements—(1) Arm’s-length contracts. (i) With the exception of those transportation allowances specified in paragraphs (c)(1)(v) and (vi) of this section, the lessee shall submit page one of the initial form ONRR–4293 prior to, or at the same time as, the transportation allowance determined pursuant to an arm’s-length contract is reported on form ONRR–4430, Solid Minerals Production and Royalty Report. (ii) The initial form ONRR–4293 shall be effective for a reporting period beginning the month that the lessee is first authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the applicable contract or rate terminates or is modified or amended, whichever is earlier. (iii) After the initial reporting period and for succeeding reporting periods, lessees must submit page one of form ONRR–4293 within 3 months after the end of the calendar year, or after the applicable contract or rate terminates or is modified or amended, whichever is earlier, unless ONRR approves a longer period (during which period the lessee VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 shall continue to use the allowance from the previous reporting period). Lessees may request special reporting procedures in unique allowance reporting situations, such as those related to spot sales. (iv) ONRR may require that a lessee submit arm’s-length transportation contracts, production agreements, operating agreements, and related documents. Documents shall be submitted within a reasonable time, as determined by ONRR. (v) Transportation allowances that are based on arm’s-length contracts and which are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For the purposes of this section, only those allowances that have been approved by ONRR in writing shall qualify as being in effect at the time these regulations become effective. (vi) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section. (2) Non-arm’s-length or no contract. (i) With the exception of those transportation allowances specified in paragraphs (c)(2)(v) and (vii) of this section, the lessee shall submit an initial form ONRR–4293 prior to, or at the same time as, the transportation allowance determined pursuant to a non-arm’s-length contract or no contract situation is reported on form ONRR– 4430, Solid Minerals Production and Royalty Report. The initial report may be based on estimated costs. (ii) The initial form ONRR–4293 shall be effective for a reporting period beginning the month that the lessee first is authorized to deduct a transportation allowance and shall continue until the end of the calendar year, or until the transportation under the non-arm’slength contract or the no contract situation terminates, whichever is earlier. (iii) For calendar-year reporting periods succeeding the initial reporting period, the lessee shall submit a completed form ONRR–4293 containing the actual costs for the previous reporting period. If the transportation is continuing, the lessee shall include on form ONRR–4293 its estimated costs for the next calendar year. The estimated transportation allowance shall be based on the actual costs for the previous reporting period plus or minus any adjustments that are based on the lessee’s knowledge of decreases or increases that will affect the allowance. form ONRR–4293 must be received by ONRR within 3 months after the end of the previous reporting period, unless PO 00000 Frm 00056 Fmt 4701 Sfmt 4700 ONRR approves a longer period (during which period the lessee shall continue to use the allowance from the previous reporting period). (iv) For new transportation facilities or arrangements, the lessee’s initial form ONRR–4293 shall include estimates of the allowable transportation costs for the applicable period. Cost estimates shall be based upon the most recently available operations data for the transportation system, or, if such data are not available, the lessee shall use estimates based upon industry data for similar transportation systems. (v) Non-arm’s-length contract or no contract-based transportation allowances that are in effect at the time these regulations become effective will be allowed to continue until such allowances terminate. For purposes of this section, only those allowances that have been approved by ONRR in writing shall qualify as being in effect at the time these regulations become effective. (vi) Upon request by ONRR, the lessee shall submit all data used to prepare its form ONRR–4293. The data shall be provided within a reasonable period of time, as determined by ONRR. (vii) ONRR may establish, in appropriate circumstances, reporting requirements that are different from the requirements of this section. (viii) If the lessee is authorized to use its Federal-agency-approved rate as its transportation cost in accordance with paragraph (b)(3) of this section, it shall follow the reporting requirements of paragraph (c)(1) of this section. (3) ONRR may establish reporting dates for individual lessees different than those specified in this paragraph in order to provide more effective administration. Lessees will be notified as to any change in their reporting period. (4) Transportation allowances must be reported as a separate line item on form ONRR–4430, unless ONRR approves a different reporting procedure. (d) Interest assessments for incorrect or late reports and failure to report. (1) If a lessee deducts a transportation allowance on its form ONRR–4430 without complying with the requirements of this section, the lessee shall be liable for interest on the amount of such deduction until the requirements of this section are complied with. The lessee also shall repay the amount of any allowance which is disallowed by this section. (2) If a lessee erroneously reports a transportation allowance which results in an underpayment of royalties, interest shall be paid on the amount of that underpayment. E:\FR\FM\07AUR3.SGM 07AUR3 Federal Register / Vol. 82, No. 150 / Monday, August 7, 2017 / Rules and Regulations mstockstill on DSK30JT082PROD with RULES3 (3) Interest required to be paid by this section shall be determined in accordance with § 1218.202 of this chapter. (e) Adjustments. (1) If the actual transportation allowance is less than the amount the lessee has taken on form ONRR–4430 for each month during the allowance form reporting period, the lessee shall be required to pay additional royalties due plus interest, computed pursuant to § 1218.202 of this chapter, retroactive to the first month the lessee is authorized to deduct a transportation allowance. If the actual transportation allowance is greater than the amount the lessee has estimated and taken during the reporting period, the lessee shall be entitled to a credit, without interest. (2) The lessee must submit a corrected form ONRR–4430 to reflect actual costs, together with any payment, in accordance with instructions provided by ONRR. (f) Other transportation cost determinations. The provisions of this VerDate Sep<11>2014 20:24 Aug 04, 2017 Jkt 241001 section shall apply to determine transportation costs when establishing value using a net-back valuation procedure or any other procedure that requires deduction of transportation costs. § 1206.462 [Reserved] § 1206.463 In-situ and surface gasification and liquefaction operations. If an ad valorem Federal coal lease is developed by in-situ or surface gasification or liquefaction technology, the lessee shall propose the value of coal for royalty purposes to ONRR. ONRR will review the lessee’s proposal and issue a value determination. The lessee may use its proposed value until ONRR issues a value determination. § 1206.464 Value enhancement of marketable coal. If, prior to use, sale, or other disposition, the lessee enhances the value of coal after the coal has been placed in marketable condition in PO 00000 Frm 00057 Fmt 4701 Sfmt 9990 36989 accordance with § 1206.456(h) of this subpart, the lessee shall notify ONRR that such processing is occurring or will occur. The value of that production shall be determined as follows: (a) A value established for the feedstock coal in marketable condition by application of the provisions of § 1206.456(c)(2)(i) through (iv) of this subpart; or, (b) In the event that a value cannot be established in accordance with paragraph (a) of this section, then the value of production will be determined in accordance with § 1206.456(c)(2)(v) of this subpart and the value shall be the lessee’s gross proceeds accruing from the disposition of the enhanced product, reduced by ONRR-approved processing costs and procedures including a rate of return on investment equal to two times the Standard and Poor’s BBB bond rate applicable under § 1206.458(b)(2)(v) of this subpart. [FR Doc. 2017–16571 Filed 8–4–17; 8:45 am] BILLING CODE 4335–30–P E:\FR\FM\07AUR3.SGM 07AUR3

Agencies

[Federal Register Volume 82, Number 150 (Monday, August 7, 2017)]
[Rules and Regulations]
[Pages 36934-36989]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2017-16571]



[[Page 36933]]

Vol. 82

Monday,

No. 150

August 7, 2017

Part III





Department of the Interior





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Office of Natural Resources Revenue





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30 CFR Parts 1202 and 1206





Repeal of Consolidated Federal Oil & Gas and Federal & Indian Coal 
Valuation Reform; Final Rule

Federal Register / Vol. 82 , No. 150 / Monday, August 7, 2017 / Rules 
and Regulations

[[Page 36934]]


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DEPARTMENT OF THE INTERIOR

Office of Natural Resources Revenue

30 CFR Parts 1202 and 1206

[Docket No. ONRR-2017-0001; DS63644000 DR2000000.CH7000 178D0102R2]
RIN 1012-AA20


Repeal of Consolidated Federal Oil & Gas and Federal & Indian 
Coal Valuation Reform

AGENCY: Office of Natural Resources Revenue, Interior.

ACTION: Final rule.

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SUMMARY: The Office of Natural Resources Revenue (ONRR) is repealing 
the Consolidated Federal Oil & Gas and Federal & Indian Coal Valuation 
Reform Final Rule, published July 1, 2016, and effective January 1, 
2017. Simultaneously, ONRR is reinstating the valuation regulations 
governing the valuation of Federal oil, Federal gas, and Federal and 
Indian coal that were in effect before January 1, 2017.

DATES: This rule is effective on September 6, 2017.

FOR FURTHER INFORMATION CONTACT: For questions on technical issues, 
contact Elizabeth Dawson at (303) 231-3653, Amy Lunt at (303) 231-3746, 
Peter Christnacht at (303) 231-3651, or Karl Wunderlich at (303) 231-
3663.

SUPPLEMENTARY INFORMATION: 

I. Background

A. General

    This final rule repeals in its entirety the Consolidated Federal 
Oil & Gas and Federal & Indian Coal Valuation Reform Final Rule (2017 
Valuation Rule) that ONRR published in the Federal Register on July 1, 
2016 (81 FR 43338), and that was effective on January 1, 2017. The 2017 
Valuation Rule made changes to existing regulations governing royalty 
valuation and reporting practices for oil, gas, and coal. As stated in 
the 2017 Valuation Rule's preamble, the purpose of implementing the 
rule was (1) to offer greater simplicity, certainty, clarity, and 
consistency in product valuation for mineral lessees and mineral 
revenue recipients; (2) to ensure that Indian mineral lessors receive 
the maximum revenue from coal resources on their land, consistent with 
the Secretary's trust responsibility and lease terms; (3) to decrease 
industry's cost of compliance and ONRR's cost to ensure industry 
compliance; and (4) to provide early certainty to industry and to ONRR 
that companies have paid every dollar due. 81 FR 43338.
    After the 2017 Valuation Rule was published, however, ONRR 
discovered several significant defects in the rule that would have 
undermined its purpose and intent. In addition, during the same time 
period (July 1, 2016, to the present) we received numerous comments 
from the regulated community and other members of the public, both in 
response to the proposed rule of repeal that we published in the 
Federal Register on April 4, 2017, and in other public forums, that 
were highly critical of certain provisions in the rule. In light of the 
defects that we discovered in the rule and after carefully considering 
all of the comments we received, we have decided to repeal the 2017 
Valuation Rule in its entirety, principally for the following three 
reasons:
    First, the 2017 Valuation Rule has a number of defects that make 
certain provisions challenging to comply with, implement, or enforce. 
Absent their repeal, the rule would compromise ONRR's mission to 
collect and account for mineral royalty revenues; could affect royalty 
distributions to ONRR's State and Tribal partners; and would impose a 
costly and unnecessary burden on Federal and Indian lessees.
    Second, On March 28, 2017, the President issued E.O. 13783--
Promoting Energy Independence and Economic Growth, 82 FR 16093. The 
executive order directs Federal agencies to review all existing 
regulations and other agency actions and, ultimately, to suspend, 
revise, or rescind any such regulations or actions that unnecessarily 
burden the development of domestic energy resources beyond the degree 
necessary to protect the public interest or otherwise comply with the 
law. Based on our own internal review, as well as on the comments we 
received both before and during the process of promulgating this rule 
of repeal, we have concluded that certain provisions of the 2017 
Valuation Rule would unnecessarily burden the development of Federal 
oil and gas and Federal and Indian coal beyond the degree necessary to 
protect the public interest or otherwise comply with the law.
    Third, on March 29, 2017, the Secretary of the Interior (Secretary) 
announced that he will reestablish the Royalty Policy Committee (RPC) 
under the Federal Advisory Committee Act. The RPC will advise ONRR on 
current and emerging issues related to the determination of fair market 
value and the collection of royalties from energy and natural resources 
on Federal and Indian lands. The RPC will be composed of Federal 
representatives and stakeholders from energy and mineral interests, 
academia, public interest groups, States, Indian Tribes, and individual 
Indian mineral interest owners. The RPC will provide a forum for 
engaging with key stakeholders and the public on many of the same 
issues we attempted to address in the 2017 Valuation Rule. ONRR expects 
that further internal assessment and analysis combined with 
consultations facilitated by the RPC's reestablishment will lead to the 
development and promulgation of a new, revised valuation rule that will 
address the various problems that have now been identified in the rule 
we are repealing.
    At the same time that we are repealing the 2017 Valuation Rule, we 
are reinstating the regulations governing the valuation of oil, natural 
gas, and coal produced from Federal leases and coal produced from 
Indian leases that were in effect before January 1, 2017. These 
regulations will apply prospectively to oil, gas, and coal produced on 
or after the effective date that we have specified in the DATES section 
of this preamble. We intend to apply and construe the prior regulations 
in a manner consistent with the preambles published in conjunction with 
the original rulemakings and in accordance with administrative and 
judicial decisions interpreting these regulations.
    Finally, upon taking effect, this repeal of the 2017 Valuation Rule 
will supersede the notification of the postponement of the 
effectiveness of the rule that we published in the Federal Register on 
February 27, 2017. 82 FR 11823. When this repeal takes effect, the so-
called administrative stay of the rule will be lifted.

B. Secretary's Authority To Promulgate Regulations or Reinstate Prior 
Regulations Under FOGRMA

    Section 301 of the Federal Oil and Gas Royalty Management Act 
(FOGRMA), as amended, codified at 30 U.S.C. 1751, grants the Secretary 
broad authority to prescribe such rules and regulations, issued in 
conformity with the Administrative Procedure Act (APA), as he deems 
reasonably necessary to create a thorough system for collecting and 
accounting for Federal and Indian mineral royalties. FOGRMA creates the 
legal framework for the collection and accounting system, but FOGRMA 
also grants the Secretary, acting through ONRR, broad discretion as to 
how to build it out. Put another way (as courts sometimes have), FOGRMA 
grants the Secretary, acting through ONRR, broad discretion to regulate 
interstitially to interpret and implement the statute.
    There is not a single right way for ONRR to exercise its 
congressionally

[[Page 36935]]

delegated authority to interpret and implement FOGRMA; on the contrary, 
there are many ways in which ONRR may legitimately accomplish its task, 
as long as the way it chooses is consistent with the statutory language 
and the congressionally prescribed legal framework. ONRR believes that 
the prior regulations, which will be reinstated by this final rule, are 
fully consistent with FOGRMA and other applicable federal statutes and 
are an effective and efficient means of valuing Federal and Indian 
minerals, as evidenced by their long and successful use before the 
promulgation of the 2017 Valuation Rule.

C. Chronology of Events Following Promulgation of 2017 Valuation Rule

    On July 1, 2016, ONRR published the final 2017 Valuation Rule in 
the Federal Register. Although the rule took effect on January 1, 2017, 
first reports and royalty payments under it were not due until February 
28, 2017.
    To facilitate the transition to the new regulations, ONRR conducted 
eleven training sessions for industry reporters in different locations 
between October 17, 2016, and December 15, 2016. We designed the 
training sessions to educate affected parties on how to value 
production and report and pay royalties under the 2017 Valuation Rule. 
The trainings also provided a forum in which lessees could ask us 
questions about the rule and how ONRR would implement and enforce it. 
At the same time that ONRR was conducting the trainings and reviewing 
comments and questions about the rule, ONRR was also receiving numerous 
written requests for guidance that asked many of the same questions 
that were being raised at the live sessions.
    The feedback we received through the training sessions and guidance 
requests revealed certain unforeseen defects in, or unintended 
consequences of, portions of the 2017 Valuation Rule. Lessees raised 
multiple questions that ONRR had not previously considered and was not 
prepared or able to answer, particularly with respect to the coal 
valuation provisions. For example, lessees argued that valuing coal 
based on the first arm's-length sale of coal as electricity is a 
difficult task because the sale price of electricity does not reflect 
the value of coal in a simple, predictable fashion--electricity markets 
are too diverse and complex to trace electricity prices back to the 
lease. Lessees also asked questions about how to value coal production 
in certain non-arm's-length transactions under the new definition of 
``coal cooperative.'' And lessees asked ONRR specific questions that we 
had not previously considered about how, and under what circumstances, 
we would implement the default provision with respect to oil, gas, and 
coal. At bottom, by the middle of December 2016 we had become aware 
that the rule contained several defects that, at a minimum, would 
seriously complicate, and probably compromise, ONRR's ability to 
implement and enforce certain provisions.
    On December 29, 2016, three different sets of petitioners, some of 
whom had previously requested guidance from ONRR, filed three separate 
petitions challenging the 2017 Valuation Rule in the United States 
District Court for the District of Wyoming. The petitioners alleged 
that the rule created widespread uncertainty about reporting and 
payment of royalties, and in some respects, was unreasonably difficult 
to comply with. The petitioners' arguments echoed the questions and 
concerns that had been raised at the reporter training sessions and in 
various guidance requests.
    By late January 2017 we recognized that implementing the 2017 
Valuation Rule would be contrary to the rule's stated purpose of 
offering greater simplicity, certainty, clarity, and consistency in 
product valuation. We also recognized that the defects in the rule were 
significant enough that implementation could undermine and compromise 
ONRR's mission to collect, account for, and verify mineral royalties 
for the United States and its State and Tribal partners.
    With the February 28, 2017, reporting deadline approaching and 
while we were actively considering internally what to do about the 
previously identified defects in the 2017 Valuation Rule, the 
petitioners in the litigation sent ONRR a letter (dated February 17, 
2017) requesting that ONRR postpone the rule's effective date. Prompted 
by that request, but based on ONRR's own independent assessment of the 
defects in the rule and the harm that could result by requiring lessees 
to comply with it, we decided that it was in the best interest of the 
regulated community, the royalty beneficiaries, and the public in 
general to preserve the regulatory status quo while the litigation was 
pending. Accordingly, on February 27, 2017, we published in the Federal 
Register a notification postponing the effectiveness of the rule 
pursuant to 5 U.S.C. 705 of the APA, pending judicial review. 82 FR 
11823.
    Meanwhile, the nation had elected a new President in November 2016, 
and the new administration had taken office on January 20, 2017. On 
March 28, 2017, the President issued E.O. 13783--Promoting Energy 
Independence and Economic Growth, 82 FR 16093, which directed the heads 
of executive agencies to review all existing regulations, orders, 
guidance documents, policies, and other similar agency actions that 
potentially burden the development or use of domestically produced 
energy resources and, ultimately, to suspend, revise, or rescind those 
agency actions that do so unnecessarily. The executive order provided 
additional impetus to our ongoing review of the 2017 Valuation Rule, 
and we discovered some additional substantive problems with the rule.
    As a result of all of those developments, on April 4, 2017, we 
published in the Federal Register a notice proposing to repeal the 2017 
Valuation Rule in its entirety and soliciting public comment on the 
proposal. 82 FR 16323. At the same time, we recognized that certain 
provisions in the 2017 Valuation Rule had been, and continued to be, 
well received. Therefore, concurrent with the proposed repeal, we also 
published an Advance Notice of Proposed Rulemaking soliciting public 
comment on two scenarios: (1) If the 2017 Valuation Rule were repealed, 
whether a new valuation rule is needed and, if so, what particular 
issues the new valuation rule should address; and (2) if the 2017 
Valuation Rule were not repealed, what changes should be made to the 
rule (82 FR 16325, April 4, 2017).
    The comment period for the proposed repeal rule closed on May 4, 
2017. We received more than a thousand comments from 2,342 commenters 
both for and against repeal. We carefully considered all of the 
comments we received and, for the reasons discussed further below, have 
decided at this time to repeal the 2017 Valuation Rule in its entirety. 
ONRR will continue to assess the substantive issues addressed in the 
2017 Valuation Rule and expects to in the near future promulgate a new, 
revised valuation rule that will address the various problems that have 
been identified in the rule we are repealing.

D. Substantive Defects in, and Administrative Challenges Posed by, the 
2017 Valuation Rule

1. Valuing Coal Using the Sale Price of Electricity
    The 2017 Valuation Rule required lessees to value certain non-
arm's-length sales of Federal and Indian coal based on the first arm's-
length sale of electricity. For several reasons we have concluded that 
this provision of the rule is unnecessarily complicated and burdensome 
to implement or enforce.

[[Page 36936]]

    ONRR has long valued oil, gas, and coal based on the first arm's-
length sale of the resource because we believe that such sales are the 
best indicator of market value. In promulgating the 2017 Valuation 
Rule, ONRR incorrectly assumed that it would be reasonable for lessees 
to ``net back'' to the value of coal from arm's-length electrical 
sales, the same way that lessees ``net back'' to value from the first 
arm's-length sale by an affiliate. We also incorrectly assumed that 
using such sales would accurately reflect the value of coal because the 
majority of coal mined from Federal and Indian lands is used to 
generate electricity. But we failed to fully consider other factors 
that determine what a generating company charges for its electricity. 
The price of electricity also reflects the company's costs to 
construct, operate, and maintain its depreciable capital assets; its 
costs to operate and maintain other necessary infrastructure; its costs 
to comply with applicable Federal and State laws; and its corporate 
overhead and other internal corporate costs. All of those factors may 
(and do) vary from company to company and from state to state. Unlike 
an arm's-length sale of coal, where the sale price directly and 
accurately reflects the value of the coal, the sale price of 
electricity is determined by many factors in addition to the price of 
coal.
    Moreover, electricity is generated, transmitted, and distributed 
through regional grids where the electricity is maintained for delivery 
at specified voltages and frequencies. The regional grids function as 
pools that are fed by electricity generated from a variety of different 
resources, including natural gas, solar, wind, geothermal, and coal. 
The electricity is then sold in wholesale markets in a variety of ways, 
including, but not limited to, firm and non-firm sales, long-term and 
short-term sales, interruptible sales, and daily spot-market sales. The 
markets also include ancillary services, such as spinning and non-
spinning reserves, voltage and frequency control, and load following. 
Each of these sales commands a different price. We have concluded at 
this time that the approach taken in the 2017 Valuation Rule 
establishes an unreasonable requirement for the lessee or ONRR to 
dissect these services and sales, and trace those sales back to coal 
produced from the lease, particularly because electricity generated 
from coal is pooled with electricity generated from other resources 
before it is sold. In short, it would be very challenging for lessees 
to calculate and pay royalties based on the sale price of electricity 
and similarly challenging for ONRR to verify the accuracy of those 
calculations.
    Finally, the 2017 Valuation Rule failed to address the increasingly 
common situation in which gross proceeds accrue to a lessee's 
affiliate. The rule stated that lessees value their Federal and Indian 
coal production on ``the gross proceeds accruing to you for the power 
plant's arm's-length sales of the electricity less applicable 
transportation and washing deductions.'' (Emphasis added.) As used in 
that regulation, the word ``you'' referred to the lessee, which the 
rule defined as ``any person to whom the United States, an Indian 
Tribe, and/or individual mineral owner issues a lease, and any person 
who has been assigned all or part of record title, operating rights, or 
an obligation to make royalty or other payments by the lease.'' For 
Federal and Indian coal, the definition of lessee included ``an 
operator, payor, or other person with no lease interest who makes 
royalty payments on the lessee's behalf.'' The rule was silent, 
however, on how to value coal when the gross proceeds accrued to a 
lessee's affiliate. This oversight would have undermined ONRR's mission 
and responsibility to collect and verify royalties, which would have 
had a direct impact on revenue accruing to ONRR's State and Tribal 
partners.
2. Definition of ``Coal Cooperative''
    The 2017 Valuation Rule defined ``coal cooperatives'' to capture 
the arm's-length value of coal in those limited circumstances in which 
unaffiliated companies cooperate to market and exchange coal for mutual 
economic advantage. But the term was defective in several respects. At 
bottom, the definition was overly broad and ambiguous and created too 
much confusion to be effective or enforceable. And because the 
definition was too broad, it asked lessees to perform an unreasonably 
difficult task, that is, to value coal based on the sale price received 
by a third-party company that was neither affiliated, nor in a 
contractual relationship, with the lessee.
    More specifically, the 2017 Valuation Rule did not define what 
entities are included in a coal cooperative, nor did the rule 
adequately identify what type of behavior, conduct, or economic 
relationships constitute a coal cooperative. Thus, the rule did not 
provide lessees with meaningful direction to enable them to determine 
whether they are part of a coal cooperative and, if so, what other 
entities may also be part of that cooperative. Indeed, the definition 
was so broad that it would have captured almost any entity engaged in 
the production, marketing, and transportation of coal, regardless of 
how far removed that entity was from the lessee. Consequently, it would 
have been unreasonable for either ONRR or the lessee to determine where 
the coal cooperative began and where it ended. By extension, it would 
have been unreasonable for either ONRR or the lessee to determine when 
the first arm's-length sale occurred. As a result, lessees could not 
have valued their coal, and ONRR (or States or Tribes, acting under 
authority by ONRR) could not have verified that value. That inadvertent 
and unfortunate confusion was, of course, directly contrary to ONRR's 
intent when it promulgated the rule.
    What is more, the definition would have required lessees to perform 
an unreasonably difficult task. For example, a federal lessee in a coal 
cooperative could sell its coal to an unaffiliated third party that is 
also in the cooperative. But because the parties are part of the same 
cooperative, we would not have considered that sale to be an arm's-
length transaction. The third party then could have transferred the 
coal to an affiliate, who could have sold the coal at arm's-length. 
Under those circumstances, the rule would have required the lessee to 
value its coal based on the sales price received by the third-party's 
affiliate, a company that was neither affiliated, nor in a contractual 
relationship, with the lessee. Under this scenario, the lessee probably 
could not have obtained the sales price information it needed to 
determine the royalty-bearing value of its coal.
    Last, the definition of coal cooperative was unnecessary because it 
attempted to solve a problem that was already addressed by the prior 
(and soon-to-be-reinstated) regulations. In the example, under the 
prior regulations ONRR would still obtain fair market value for the 
coal because the lessee and third party lack opposing economic 
interests, and we therefore would apply the provision in the 
regulations for valuing coal in non-arm's-length transactions. Under 
that provision, depending on the circumstances, ONRR could still value 
the coal based on the first arm's-length transaction under the fourth 
benchmark in 30 CFR 1206.257(c)(2) (Federal coal) or 1206.456(c)(2) 
(Indian coal).
3. Default Provision
    Statutes and lease terms grant the Secretary considerable authority 
and discretion to establish the reasonable value of Federal and Indian 
minerals. By promulgating the so-called default provision, ONRR was 
attempting to offer greater clarity, consistency, and

[[Page 36937]]

predictability by defining when, where, and how the Secretary would 
exercise his discretionary authority to use an alternative methodology 
to value minerals. We attempted to explain that we would invoke the 
default provision only in specific and limited situations when we could 
not determine whether a lessee had properly paid royalties under the 
regulations. Those situations include when a lessee fails to provide 
documents during an audit, when a lessee engages in misconduct, when a 
lessee breaches its duty to market, or any other situation that 
compromises our ability to reasonably determine the fair market value 
of the oil, gas, or coal. But because we described those circumstances 
so broadly, without limits or meaningful guidance, the rule created 
more confusion and uncertainty than it resolved.
    We also failed to appreciate the numerous administrative challenges 
posed by the default provision. For example, the 2017 Valuation Rule 
did not identify who within ONRR has the authority to invoke the 
default provision or whether that decision must be approved or may be 
appealed. The rule defined ``misconduct'' so broadly that lessees, 
ONRR, and ONRR's State and Tribal partners were left without any 
meaningful guidance on what type of misconduct triggered the default 
provision. At the same time, the rule was silent on whether ONRR must 
make a formal finding of misconduct before the default provision is 
invoked, who has the authority make such a finding, and whether such a 
finding is subject to review. We believe that those ambiguities would 
have led to very inconsistent applications of the rule.
    The 2017 Valuation Rule also did not address whether the default 
provision was a tool of last resort or a vehicle to collect and verify 
royalties more efficiently. For example, the rule offered no guidance 
on what would happen if ONRR invoked the default provision to value 
production because the lessee failed to provide documents necessary to 
value the production, and the lessee later produces those documents. 
Nor did the rule fully explain how the default provision interacted 
with ONRR's civil penalty regulations. For example, if a lessee 
knowingly or willfully fails to provide documents during an audit, the 
rule was silent on whether ONRR would issue a civil penalty for failing 
to permit an audit, or whether ONRR would complete the audit by valuing 
the production under the default provision, or both. These challenges, 
and many others, made the default provision confusing to lessees and 
would have made it difficult, for ONRR to implement and enforce.
    Finally, with or without the default provision, ONRR already has 
the authority to establish the value of Federal and Indian minerals 
when we cannot determine whether a lessee properly paid royalties. 
While the default provision was a well-intended attempt to provide 
certainty and predictability by clarifying and codifying that 
authority, we now recognize that the default provision created more 
confusion, uncertainty, and apprehension than it resolved.
4. Requirement That Arm's-Length Contracts Be in Writing and Signed by 
All Parties
    The 2017 Valuation Rule required both lessees and their affiliates 
to reduce all contracts, contract revisions, or amendments to writing 
and have them signed by all of the parties. The rule further stated 
that where the lessee did not have in place a written contract signed 
by all of the parties, ONRR could use the default provision to value 
the oil, gas, or coal at issue.
    Based on the comments we received, we have reconsidered our 
position on this requirement. We now agree with the majority of 
commenters that this provision of the rule is unnecessary, overly 
burdensome, and potentially defective. First, this provision overlooked 
the fact that unwritten agreements or unsigned, written agreements may 
be binding, legally enforceable contracts. Second, this provision 
contradicted the definition of ``contract'' in the rule itself, which 
defined ``contract'' as ``any oral or written agreement . . . that is 
enforceable by law'' and which did not require the contract to be 
signed by the parties. Third, the preamble stated that ONRR could 
discount or ignore an arm's-length contact if the contract were not in 
writing and signed by all of the parties, which ran counter to ONRR's 
long-held position that arm's-length sales are the best indicator of 
market value. Fourth, the rule required the lessees' affiliates to have 
all of their contracts, contract revisions, and amendments reduced to 
writing and signed by all of the parties, despite the fact that the 
affiliates are not Federal or Indian lessees and the rule was not 
purporting to regulate them. And fifth, the rule burdened lessees and 
their affiliates with an unnecessary and potentially costly obligation 
to conform contracts to meet ONRR's specifications, which could 
increase the cost of production and delay the delivery of mineral 
resources.
5. Valuation Guidance and Determinations
    The 2017 Valuation Rule required Federal oil and gas and Indian 
coal lessees to request valuation determinations from ONRR that, 
because of an oversight in the rule, we would no longer have the 
regulatory authority to issue. The prior regulations authorized ONRR to 
issue a binding valuation determination in response to a request from 
an oil, gas, or coal lessee. The 2017 Valuation Rule, however, 
inadvertently stripped ONRR of that authority or, at the very least, 
was unclear as to whether ONRR could continue to exercise that 
authority.
    More specifically, sections 1206.108 (Federal oil), 1206.148 
(Federal gas), 1206.258 (Federal coal), and 1206.458 (Indian coal) all 
provided that a lessee could request a valuation determination from 
ONRR. The rule then provided that ONRR could do one of three things in 
response to the request: (1) Request that the Assistant Secretary for 
Policy Management and Budget issue a determination; (2) decide that 
ONRR will issue non-binding guidance; or (3) notify the lessee that 
ONRR will not provide a determination or guidance. The rule was silent, 
however, on whether ONRR could issue a valuation determination in 
response to a request. Thus, under the 2017 Valuation Rule ONRR 
arguably had no authority to continue to issue valuation 
determinations.
    This was particularly problematic because several sections in the 
2017 Valuation Rule required lessees to request valuation 
determinations from ONRR, and several other provisions required ONRR to 
issue such determinations. Those references appear in the following 
sections:

------------------------------------------------------------------------
   Federal gas        Federal oil       Federal coal       Indian coal
------------------------------------------------------------------------
1206.141(e)        1206.111(d)        1206.252(b)(2)    1206.452(b)(2)
1206.142(f)        .................  1206.261(c)       1206.461(c)
1206.153(d)        .................  1206.268(c)       1206.468(c)
1206.160(b)(2)     .................  ................  ................

[[Page 36938]]

 
1206.160(c)        .................  ................  ................
------------------------------------------------------------------------

    At bottom, this oversight means that lessees cannot comply with the 
2017 Valuation Rule and ONRR cannot enforce it, which undermines the 
purpose and intent of the rule. Even if ONRR could issue valuation 
determinations in the absence of a regulation, these sections fail to 
specify whether ONRR's determinations are binding on ONRR or the 
lessee, and if so, whether the lessee may appeal the determination. 
Other provisions of the regulations cross-reference the terms 
``valuation determinations'' and ``determinations'' without defining 
those terms or stating whether those terms are synonymous or distinct. 
In addition, section 1206.458, which applies to Indian coal, 
incorrectly provides that the Assistant Secretary for Policy, 
Management and Budget will issue a valuation determination regarding 
Indian coal. But only the Assistant Secretary for Indian Affairs has 
the authority to issue a valuation determination for questions 
concerning Indian lands. All in all, the numerous defects and the lack 
of consistency in the regulations governing valuation determinations 
undermined the purpose and intent of the rule and would have created 
confusion and inefficiencies and imposed additional burdens on both 
ONRR and the regulated community.
6. Flared Gas Valuation
    Under the 2017 Valuation Rule, lessees who are required to pay 
royalty on flared gas would have been required to value the vented and 
flared gas using an index price for the area if one is available. If an 
index price were not available, then the lessee would have been 
required to propose a method to ONRR under the default provision. In 
those circumstances, we expected that the proposed method would value 
the vented and flared gas based on the arm's-length sale price the 
lessee received for other gas sold from the same lease. ONRR now 
recognizes that this regulation would have imposed an unnecessary and 
potentially costly administrative burden on certain lessees. It would 
also have run counter to ONRR's belief and position that arm's-length 
transactions are the best indicator of value.
    For example, there is no viable index price in North Dakota. Thus, 
lessees in North Dakota would have been required to propose a method to 
ONRR under the default provision. For lessees that also sell gas 
produced from the same lease at arm's-length, we assumed that the 
lessee would propose to value its vented and flared gas on the price it 
received in the arm's-length sale. Thus, those lessees would have 
reported one volume, on one line, pursuant to a single valuation 
method.
    Lessees in the San Juan Basin in New Mexico, however, would have 
been held to a different standard. Because there is a viable index 
price in the San Juan Basin, lessees there would be required to value 
their gas using the index price. That is true even if the lessee were 
selling the same gas from the same lease at arm's length to third-party 
buyers. Under those circumstances, the lessee would be required to 
report two separate volumes, on two separate lines, using two separate 
valuation methods. This inconsistency, and the additional 
administrative burden it would impose on certain lessees, was not our 
intent when we promulgated the rule.
    In sum, the 2017 Valuation Rule would have imposed an unnecessary 
and potentially costly administrative burden on certain lessees. At the 
same time, the rule would run counter to ONRR's long-held belief and 
position that prices under arm's-length contracts are the best measure 
of value.
7. Changes in Administration and Energy Policy
    The nation elected a new President in November 2016, and the new 
administration took office on January 20, 2017. Through various public 
announcements the new administration quickly signaled that it would 
adopt and follow a national energy policy different than that of its 
predecessor, one that emphasized and prioritized the reduction of 
Federal regulatory burdens on industry. On March 28, 2017, President 
Donald J. Trump issued E.O. 13783--Promoting Energy Independence and 
Economic Growth (Executive Order) (82 FR 16093, Mar. 31, 2017). The 
Executive Order begins by stating broadly that ``[i]t is in the 
national interest to promote clean and safe development of our Nation's 
vast energy resources, while at the same time avoiding regulatory 
burdens that unnecessarily encumber energy production, constrain 
economic growth, and prevent job creation.'' The Executive Order then 
continues, ``Accordingly, it is the policy of the United States that 
executive departments and agencies (agencies) immediately review 
existing regulations that potentially burden the development or use of 
domestically produced energy resources and appropriately suspend, 
revise, or rescind those that unduly burden the development of domestic 
energy resources beyond the degree necessary to protect the public 
interest or otherwise comply with the law.'' To that end, the Executive 
Order directs the heads of all agencies to ``review all existing 
regulations, orders, guidance documents, policies, and any other 
similar agency actions (collectively, agency actions) that potentially 
burden the development or use of domestically produced energy 
resources, with particular attention to oil, natural gas, coal, and 
nuclear energy resources.'' The Executive Order defines ``burden'' to 
mean ``to unnecessarily obstruct, delay, curtail, or otherwise impose 
significant costs on the siting, permitting, production, utilization, 
transmission, or delivery of energy resources.''
    Pursuant to the Executive Order, ONRR included the 2017 Valuation 
Rule in its review of regulations that potentially burden the 
development or use of domestically produced energy resources. As a 
result of that review, we concluded that the rule, as a whole, would 
unduly burden or unnecessarily obstruct, delay, curtail, or otherwise 
impose significant costs on the production, utilization, or delivery of 
Federal oil or gas or Federal or Indian coal. For example, because we 
realized that valuing coal based on the arm's-length sale of 
electricity is a very challenging task, we concluded that Federal and 
Indian coal lessees would incur unnecessary and unwarranted costs in 
trying to comply with those provisions in the 2017 Valuation Rule. 
Likewise, because we had realized that the definition of ``coal 
cooperative'' in the rule was too broad and ambiguous to comply with or 
enforce, we concluded that lessees in cooperatives would incur 
unnecessary and unwarranted costs in an effort to determine the 
royalty-bearing value of their coal. These defects alone would have 
resulted in significant costs that would have served as a financial 
disincentive to producing coal from Federal or Indian lands.
    In sum, a number of provisions of the 2017 Valuation Rule would 
have unnecessarily obstructed, delayed,

[[Page 36939]]

curtailed, or otherwise imposed significant costs on the production, 
utilization, or delivery of Federal oil and gas and Federal and Indian 
coal. The repeal of the 2017 Valuation Rule therefore is consistent 
with the policy announced in the Executive Order and the direction that 
the Executive Order provides to executive agencies. The Department 
takes seriously its responsibility to ensure that taxpayers receive the 
full value from Federal mineral leases, which is why ONRR intends to 
continue to consider future changes and develop a new rulemaking after 
further analysis and consultations with our key stakeholders and the 
general public.

II. Comments on Proposed Rules

    On April 4, 2017, ONRR published a Notice of Proposed Rulemaking 
(NPRM) to invite public comment on the possible repeal of the 2017 
Valuation Rule. 82 FR 16323. During the 30-day public comment period, 
we received more than one thousand pages of written comments from over 
2,342 commenters. We received comments from industry, industry trade 
groups, Members of Congress, State governors and agencies, local 
municipalities, Tribes, local businesses, public interest groups, and 
individual commenters. The majority of comments--both those opposing 
and those supporting repeal--addressed the Federal and Indian coal 
valuation provisions in the 2017 Valuation Rule.
    Comments opposing repeal of the 2017 Valuation Rule generally 
argued that repealing the 2017 Valuation Rule would result in 
undervaluing our nation's oil, gas, and coal resources; would result in 
a waste of government resources; and would violate certain provisions 
in the APA.
    Comments supporting repeal of the 2017 Valuation Rule generally 
faulted the following elements of the rule: (a) The method that lessees 
must use to calculate value on coal sold under non-arm's-length 
contracts; (b) ONRR's definition of ``contract'' and ``misconduct''; 
(c) the default provision; (d) changes to transportation and processing 
allowances; (e) the option to value Federal gas sold under non-arm's-
length transactions based on index prices; and (f) percentage-of-
proceeds contracts.

A. General Comments

    Public Comment: Many commenters who work in the coal industry or 
live in coal-mining-dependent communities, including a tribe, 
maintained that the 2017 Valuation Rule went too far. They argued that 
the 2017 Valuation Rule imposed unwarranted valuation methods, which, 
they contended, hinder transparency and create complex and subjective 
oil, gas, and coal valuations. They claimed that the 2017 Valuation 
Rule would cause economic harm to the oil, gas, and coal industries, 
including the loss of jobs.
    ONRR also received a few comments advocating that oil, gas, and 
coal production should stop and that the minerals should ``stay in the 
ground.''
    ONRR Response: We agree that the 2017 Valuation Rule's process for 
using the sale price of electricity to value coal would be too complex 
to comply with, implement, or enforce. We also agree that other aspects 
of the 2017 Valuation Rule, including the default provision and the 
definition of coal cooperative, are too broad to be implemented 
effectively, which could make reporting and paying royalties more 
burdensome and less predictable and transparent.
    Although we appreciate the comments regarding keeping fossil fuels 
in the ground and the socioeconomic impact of the 2017 Valuation Rule 
on communities that rely on coal production, both issues are beyond the 
scope of this rulemaking.
    Public Comment: An industry trade group commented that complexities 
in the 2017 Valuation Rule would make it difficult for small businesses 
to comply. The commenter also claimed that smaller companies would not 
be able to take deductions, resulting in a higher royalty rate.
    ONRR Response: For the reasons stated previously, we agree that 
implementing the rule would increase the costs of compliance and 
unnecessarily burden the production of Federal and Indian mineral 
resources. We also agree that those increased compliance costs could 
disproportionately impact smaller companies that have fewer resources 
to comply.
    Public Comment: We received comments from two States asserting that 
repealing the rule would unfairly reduce the royalties that the States 
receive under the 2017 Valuation Rule. Conversely, we received a 
comment from another State asserting that not repealing the rule would 
result in decreased production that would adversely affect its royalty 
share.
    ONRR Response: Based on our economic analysis, we recognize that 
repealing the 2017 Valuation Rule will result in a decrease in 
royalties (between 0.8 percent and 1.0 percent) to our State partners 
compared to what they would receive if ONRR implemented and enforced 
the rule. ONRR will continue to assess options for updating our 
valuation regulations and expects to, in the near future, propose new 
rules that could offset, in whole or in part, the decrease in royalties 
shared with State partners in future years compared to what would 
otherwise result from the repeal of the 2017 Valuation Rule. As 
discussed previously, the rule has a number of defects that make 
certain provisions challenging to comply with, implement, or enforce. 
ONRR's attempt to implement or enforce the rule as written would have 
compromised our ability to collect and account for mineral royalty 
revenues, which in turn may have affected distributions to other 
royalty beneficiaries. It would also have imposed an additional 
financial and administrative burden on our State and Tribal partners, 
who audit and verify royalty payments.
    We also agree with the State commenter that implementing the 2017 
Valuation Rule could result in some decreased production, particularly 
for coal, because the burden of complying with certain provisions of 
the rule would serve as a disincentive to production. This too would 
result in decreased royalty distributions to our State and Tribal 
partners. All told, we believe that the modest economic gains that 
might result from implementing the rule are far outweighed by the 
potentially significant burden on industry, ONRR, and our State and 
Tribal partners from implementing and enforcing a rule with significant 
defects.
    Public Comment: Industry trade groups claimed that the 2017 
Valuation Rule was unnecessarily complex, which would increase the 
costs of complying with the regulation. The groups maintained that the 
complexity and costs would discourage industry from entering into 
Federal or Indian leases.
    ONRR Response: ONRR agrees that several unforeseen defects in the 
2017 Valuation Rule have the potential to significantly increase the 
cost and administrative burden of compliance, which could create a 
disincentive to entering into, and producing oil, gas, and coal from, 
Federal or Indian leases.
    Public Comment: We received comments encouraging collaboration with 
our stakeholders in any future rulemaking. Many industry commenters 
encouraged working through the RPC to advise ONRR on valuation 
policies.
    ONRR Response: As discussed previously, the Secretary has recently 
re-established the RPC to collaborate with our stakeholders in any 
future rulemaking. The RPC will provide a forum for engaging with the 
public on many of the same issues we attempted to address in the 2017 
Valuation Rule.

[[Page 36940]]

We look forward to working with our stakeholders in the RPC on a future 
rulemaking.

B. Fair Return to Government

    Public Comment: Many commenters and comments disagreed about the 
need either to revise or to repeal the 2017 Valuation Rule. Some public 
interest groups and some members of the public asserted that ONRR's 
regulations have undervalued royalties for many years and that the 
changes made in the rule would ensure that royalties are based on fair 
market value. Industry trade groups and other members of the public 
maintained that the rule would result in values that inflate the value 
of the resources.
    ONRR Response: We disagree that repealing the rule will prevent the 
government from receiving a fair market value for its mineral 
resources. The prior (and soon-to-be-reinstated) regulations have been 
in place for more than twenty years and serve as a reasonable, 
reliable, and consistent method for valuing Federal and Indian minerals 
for royalty purposes. This is evidenced by the fact that when we 
promulgated and published the final 2017 Valuation Rule, we estimated 
that it would generate less than 1 percent in additional royalties. 81 
FR 43359. Moreover, as we discussed in proposing the 2017 Valuation 
Rule, we were attempting to make ``proactive and innovative changes'' 
to the rules ``to increase the effectiveness and efficiency of the 
rules.'' We believe today, as we always have, that the prior (and soon-
to-be-reinstated) regulations provide a fair market return for Federal 
and Indian minerals. That said, we will continue to look for 
opportunities to improve our regulations, including opportunities to 
improve the return to taxpayers and Indian mineral owners and to 
streamline processes for both ONRR and industry.
    Public Comment: A public interest group maintained that our 
regulations should use a market value based on the value of the 
resource where it is ultimately consumed. The comment asserted that 
ONRR does not collect royalties at the market and that we should more 
aggressively pursue a value at the market instead of a value at the 
lease.
    ONRR Response: While we appreciate the comment, whether ONRR should 
use a market value based on the value of the resource where it is 
ultimately consumed is outside the scope of this rulemaking.

C. Administrative Procedure Act (APA)

    One member of Congress, two State officials, and several public 
interest groups asserted that ONRR failed to comply with certain 
requirements in the APA.
    Public Comment: Some commenters stated that ONRR's decision to 
postpone the effectiveness of the 2017 Valuation Rule indicates ONRR's 
intent to repeal the rule, without regard to any comments received in a 
rulemaking process, in violation of APA rulemaking requirements.
    ONRR Response: The 2017 Valuation Rule was effective on January 1, 
2017. On February 27, 2017, for the reasons discussed in the preamble 
to this rule, including the filing of three separate petitions 
challenging the rule in the United States District Court for the 
District of Wyoming, ONRR postponed the effectiveness of the rule, 
pending judicial review. 82 FR 11823. ONRR did not decide to repeal the 
2017 Valuation Rule, however, until after we had reviewed and 
considered of all comments that we received in response to the proposed 
rule of repeal, which we published in the Federal Register on April 4, 
2017. 82 FR 16323.
    Public Comment: We also received comments contending that ONRR did 
not provide a reasoned basis to repeal the rule.
    ONRR Response: We are providing a reasoned basis to repeal the rule 
in the preamble to this rule. Before we proposed to repeal the 2017 
Valuation Rule, we identified several defective provisions in the rule 
that would have made these provisions unnecessarily complicated and 
burdensome to comply with, implement, or enforce. When we published the 
proposed rule of repeal on April 4, 2017, we identified some of those 
defects and specifically invited public comment on them as well as on 
other aspects of the 2017 Valuation Rule.
    Public Comment: Public interest groups and some individuals claimed 
that the 30-day comment period in the NPRM is unreasonable and violates 
the APA. The commenters asserted that ONRR went to great effort to 
promulgate the 2017 Valuation Rule and was now proposing to repeal it 
with only a 30-day comment period.
    ONRR Response: Under the APA's rulemaking procedures, agencies must 
publish a notice of proposed rulemaking in the Federal Register; allow 
interested persons an opportunity to comment on the proposed rule; and, 
after considering those comments, publish the final rule. The APA 
requires an opportunity to submit ``written data, views, or 
arguments,'' yet there is no required minimum comment period under the 
APA. See 5 U.S.C. 553(c). Through this rulemaking we are complying with 
the requirements set forth in the APA. We provided a reasonable amount 
of time to allow interested parties a sufficient opportunity to 
consider the repeal and its supporting analysis and to provide 
meaningful comments.
    Public Comment: One commenter asserted that ONRR must analyze the 
record compiled to issue the rule and provide a reasoned explanation 
for the repeal. According to the commenter, ONRR has not cited any new 
scientific or technical information in support of repeal.
    ONRR Response: The comment is not clear on whether it refers to the 
record for the 2017 Valuation Rule or the record for the repeal of the 
2017 Valuation Rule. Regardless, we provided the purpose and 
justification for both rules and responded to comments that we received 
during both rulemakings. Specifically, we analyzed the record compiled 
during the 2017 Valuation Rule rulemaking. 81 FR 43338. In the preamble 
and responses to comments for this final rule, ONRR also analyzed the 
record compiled for the proposed repeal. We have determined to repeal 
the 2017 Valuation Rule for the reasons stated herein.

D. Government Efficiency

    Public Comment: One member of Congress and a public interest group 
asserted that repealing the rule amounts to wasting government 
resources because ONRR is abandoning the work that it performed while 
promulgating the 2017 Valuation Rule. These commenters also argued that 
if there are problems with the rule, ONRR should address those problems 
separately and not necessarily abandon the rule in its entirety.
    ONRR Response: We disagree that repealing the rule is a waste of 
government resources. As noted previously, the 2017 Valuation Rule has 
several defects that make certain provisions unnecessarily complicated 
and burdensome to comply with, implement, or enforce. We have concluded 
that those defects are significant enough that implementing the rule 
would compromise our mission to collect and account for mineral royalty 
revenues for Federal oil and gas and Federal and Indian coal. The cost 
of implementing the rule and subsequently trying to fix the defects in 
one or more separate rulemakings would far exceed the cost of repealing 
and replacing the rule.

[[Page 36941]]

    We also disagree that ONRR is abandoning the work that it 
previously performed. As noted previously, the Secretary is 
reestablishing the RPC to increase stakeholder engagement on many of 
the same issues the 2017 Valuation Rule attempted to address. We hope 
and expect that this new round of public engagement will lead to the 
development of a new valuation rule. The work that ONRR performed while 
promulgating the 2017 Valuation Rule, as well as the stakeholder 
comments during that rulemaking, will no doubt serve as valuable 
resources for the RPC as it fulfills its charge to advise ONRR on 
current and emerging issues related to the determination of fair market 
value and the collection of royalties from resources on Federal and 
Indian lands.

E. Federal and Indian Coal Valuation

    For coal not sold under arm's-length contracts, the 2017 Valuation 
Rule removed the ability for lessees to use the benchmarks found in the 
prior (and soon-to-be-reinstated) regulations. Instead, under the 2017 
Valuation Rule lessees had to value their coal on the first arm's-
length sale of the coal. In cases where that first arm's-length sale 
was for the sale of electricity, lessees had to use the prices that 
they received for electricity to ``net back'' to the value of the coal 
at the lease.

1. Valuing Coal Based on Benchmarks

    Public Comment: ONRR received numerous comments from industry, 
government officials, industry trade groups, public interest groups, 
and the general public regarding how lessees should value Federal and 
Indian coal not sold at arm's length.
    Some commenters maintained that the prior rule's non-arm's-length 
valuation benchmarks fail to capture the true value of coal that 
lessees sell in non-arm's-length transactions. The commenters posited 
that the benchmarks do not allow ONRR to determine royalty value based 
on a coal lessee's affiliate's subsequent arm's-length sale, including 
overseas sales, resulting in the coal industries taking advantage of a 
``loophole.'' These commenters maintained that the most effective 
method to determine the value of Federal and Indian coal not sold under 
arm's-length contracts is to use the first arm's-length sale of coal 
sold by the lessee's affiliate.
    ONRR also received comments from industry, government officials, 
industry trade groups, and the general public that supported repealing 
the rule because they found the old benchmarks to be time-tested and 
robust. These commenters maintained that the 2017 Valuation Rule's 
method to determine value for royalty purposes when Federal and Indian 
lessees do not sell their coal at arm's-length was difficult to 
implement and did not establish an appropriate value, for royalty 
purposes, of Federal or Indian coal at the mine. One commenter asserted 
that the rule amounted to an unlawful royalty on the value of services 
that an affiliate provides to the lessee.
    ONRR Response: We believe that arm's-length transactions generally 
are the best indicators of market value because they provide a 
consistent and accurate measure of value. But we do not agree that the 
benchmarks in the prior (and soon-to-be-reinstated) regulations create 
a ``loophole'' that permits coal lessees to shirk their royalty 
obligations. Indeed, ONRR has used the benchmarks to order additional 
royalties due based on an affiliate's arm's-length sale, including in 
those circumstances in which the coal is sold by the affiliate in the 
international market. While we recognize that the benchmarks are 
sometimes difficult to apply, we also recognize that benchmarks are a 
proven and time-tested method for determining the fair value of Federal 
and Indian coal that the lessee does not sell at arm's-length.
2. Valuing Coal Based on ``Net Back'' From Electric Sales
    Public Comment: Numerous coal companies and a coal industry trade 
group expressed a range of concerns about using electric sales to value 
coal sold in non-arm's-length situations without competing economic 
interests. In particular, these commenters highlighted extraordinary 
complexities in electric markets and the electric producers' resource 
portfolios. They objected to valuing coal by way of electricity, which 
the commenters asserted is a separate commodity subject to its own 
unique market factors and forces and regulatory requirements, and 
argued that geothermal regulations were inappropriate as a means for 
determining transmission and production allowances. Overall, industry 
commenters argued that the 2017 Valuation Rule's effort to value coal 
through arm's-length sales of electricity was overly burdensome if not 
functionally impossible. A number of comments from the general public 
also asserted that valuing coal as electricity would make electricity 
more expensive because the increased royalty burden would be passed on 
to the consumer.
    ONRR Response: ONRR has carefully considered these comments and, as 
discussed in the preamble to this rule, has concluded and agrees that 
the 2017 Valuation Rule's process for ``netting back'' to the value of 
coal from arm's-length electrical sales is an unnecessarily complicated 
and burdensome task to perform and does not necessarily result in an 
accurate valuation of the coal.
3. Other Issues Related to Valuing Coal
    Public Comment: Two companies, one State government representative, 
three industry trade groups, and one member of the public supporting 
the repeal observed that the 2017 Valuation Rule handles coal lessees 
differently than oil and gas lessees and claimed that this treatment is 
discriminatory. They pointed out that, like coal, gas can be used to 
generate electricity, but that, unlike coal, ONRR does not require 
Federal or Indian gas lessees to value their gas production based on 
electricity sales ``netted back'' to the lease.
    ONRR Response: We did not intend to discriminate against coal by 
valuing the coal based on electricity sales. Coal, oil, and gas are all 
different commodities, subject to different market factors and forces 
and regulatory requirements. In our experience, the first arm's-length 
sale of much Federal or Indian coal is as electricity. That is rarely 
the case for Federal or Indian oil and gas.
    Public Comment: One company suggested that the costs to comply with 
the 2017 Valuation Rule's non arm's-length coal valuation provisions 
would offset any increase in royalty that ONRR would receive. The 
company further claimed that ONRR's own analysis shows that the 
royalties received from these provisions would be minimal if not 
negative.
    ONRR Response: We agree that the 2017 Valuation Rule's requirement 
to value coal based on electric sales is overly burdensome and would 
result in substantial compliance costs.

F. Definitions

1. Misconduct
    The 2017 Valuation Rule included a new definition of ``misconduct'' 
to use in conjunction with the default provision.
    Public Comment: One member of the public took issue with the 2017 
Valuation Rule's definition of the term ``misconduct.'' The commenter 
maintained that the term has derogatory implications that could affect 
a lessee's reputation. The commenter noted that the definition added 
tension between ONRR and the industry that it regulates.
    ONRR Response: We defined ``misconduct'' to clarify when ONRR would 
use its discretion to determine the value of production under the

[[Page 36942]]

default provision. We now believe the definition is too ambiguous 
because it provides almost no guidance as to what type of conduct 
qualifies as misconduct. At the same time, the rule is silent on 
whether ONRR must make a formal finding of misconduct before the 
default provision is invoked, who has the authority make such a 
finding, and whether such a finding is reviewable on appeal. Taken 
together, these ambiguities could lead to inconsistent applications of 
the rule, which would undermine the purpose and intent of the rule. 
While we cannot surmise how a finding of misconduct would impact a 
lessee's reputation, we do agree with the commenter that the ambiguity 
of the definition perpetuated (and perhaps aggravated) the tension and 
apprehension that we were attempting to rectify.
2. Coal Cooperative
    The 2017 Valuation Rule added a new definition of the term ``coal 
cooperative'' that included formal or informal organizations of 
companies or other entities sharing in a common interest to produce and 
market coal or coal-based products, the latter generally being 
electricity.
    Public Comment: One company asserted that, by determining in 
advance that transactions between coal cooperatives are non-arm's-
length, ONRR failed to take into account its longstanding criteria for 
determining whether entities are affiliated. The commenter further 
contended that ONRR has not provided any evidence to support that coal 
cooperatives are engaging in non-arm's-length transactions. The company 
concludes that this is arbitrary, capricious, and contrary to law.
    ONRR Response: For the reasons discussed in the preamble to this 
rule, we agree that the definition of coal cooperatives in the 2017 
Valuation Rule is overly broad and ambiguous and would create too much 
confusion to be effective or enforceable. We also agree that the 
definition is unnecessary because ONRR can evaluate such transactions 
on a case-by-case basis under the prior (and soon-to-be-reinstated) 
regulations.

G. Default Provision

    The 2017 Valuation Rule included the so-called default provision, 
which allowed ONRR great discretion to value a lessee's oil, gas, and 
coal production in circumstances in which we could not determine 
whether a lessee properly paid royalties under the regulations. We 
explained that such circumstances included, but were not limited to, 
the lessee's failure to provide documents, the lessee's misconduct, the 
lessee's breach of the duty to market, or any other situation that 
significantly compromises the Secretary's ability to reasonably 
determine the correct value using other measures of value.
    Public Comment: Companies and industry trade groups overwhelmingly 
opposed the default provision. Many general public commenters also 
opposed it. The commenters asserted that the default provision gave 
ONRR ``overly broad'' discretion to determine the value of production. 
An oil and gas industry trade group asserted that the default provision 
allowed ONRR to ``second guess'' lessees' reporting and payment in 
subsequent years, potentially causing lessees to incur late payment 
interest and penalties. A State official raised concerns that the 
default provision could have a chilling effect on coal production from 
Federal and Indian lands.
    Public interest groups and other members of the general public 
approved of the default provision, at least in principle. These 
commenters asserted that eliminating the default provision would hinder 
ONRR's ability to ensure a fair value of Federal and Indian mineral 
resources, specifically for coal. One public interest group stated that 
the default provision simply codified the Secretary's authority to 
determine royalty value and clarified when and how ONRR anticipated 
using that authority.
    ONRR Response: The comments alone demonstrate how the default 
provision created far more confusion, uncertainty, and apprehension 
than we intended or anticipated. Under FOGRMA, as amended, the 
Secretary indisputably has the authority and discretion to determine 
the reasonable value of Federal and Indian minerals. By promulgating 
the default provision, we attempted to offer greater clarity, 
consistency, and predictability by defining when, where, and how ONRR 
would value production in those circumstances in which we could not 
determine whether a lessee properly paid royalties under the 
regulations. We drafted the rule broadly to encompass every scenario in 
which ONRR would be forced to invoke the default provision. We realize 
now that in doing so, we provided little in the way of meaningful 
guidance on how and when ONRR would invoke its authority. Moreover, 
because the rule was so broad, it created the perception that ONRR 
would look past the valuation regulations and value production under 
the default provision regardless of whether the lessee properly 
reported and paid royalties under our regulations. This widespread 
confusion defeated the very purpose and intent of including a default 
provision in the rule.
    Also, we disagree with those commenters who claimed that 
eliminating the default provision would hinder ONRR's ability to ensure 
a fair value of Federal and Indian mineral resources. Indeed, with or 
without the default provision, ONRR has the authority to establish the 
value of Federal and Indian minerals when we cannot determine whether a 
lessee properly paid royalties under the regulations. ONRR exercised 
this authority under our prior regulations, and we will continue to 
exercise that authority now that those regulations will be reinstated. 
Typically we use this authority in limited circumstances to establish a 
reasonable value of production using market-based transaction data, 
which has always been the basis for our royalty valuation rules. 
Therefore, the repeal of the default provision will have the same small 
and speculative royalty impact as its implementation.

H. Allowances

    In the 2017 Valuation Rule ONRR eliminated the regulation allowing 
us to approve transportation allowances in excess of 50 percent of the 
value of a lessee's oil production. The rule also eliminated lessees' 
ability to net transportation costs in their gross proceeds 
calculations (``transportation factors''). The 2017 Valuation Rule also 
eliminated both our ability to grant extraordinary processing 
allowances and to approve requests for lessees to exceed the 66\2/3\ 
percent limitation on processing allowances.
    Public Comment: Coal companies and coal industry trade groups 
asserted that coal transportation allowances were poorly defined. They 
also objected to the 2017 Valuation Rule's requirement that they use 
the geothermal allowance regulations to ``net back'' to the value of 
coal where the first arm's-length sale is electricity. Oil and gas 
industry unanimously opposed the rule's cap on transportation and 
processing allowances of 50 percent and 66\2/3\ percent, respectively.
    Public interest groups generally opposed repealing the allowance 
provisions in the 2017 Valuation Rule. Some commenters suggested that 
allowance caps create more transparency and are easier to enforce. One 
public interest group advocated for eliminating all allowances, 
suggesting that they are a form of subsidy. Another public interest 
group reiterated its view

[[Page 36943]]

that coal transportation and washing allowances should, like oil and 
gas, be limited to 50 percent and 66\2/3\ percent, respectively. A 
member of the general public asserted that ONRR should give standard 
deductions for transportation and coal washing to reduce administrative 
burden and to ensure a fair return to taxpayers.
    ONRR Response: We appreciate the variety of responses, but whether 
ONRR should eliminate all transportation allowances or establish a 
standard allowance are questions that are outside the scope of this 
rulemaking. The United States shares in certain expenses that occur 
downstream or away from the lease, including costs associated with 
transportation, gas processing, and coal washing, because the United 
States benefits from lessees selling their production at a market 
instead of at the lease.
    We agree that, in practice, the requirement that coal lessees use 
the geothermal allowance regulations to ``net back'' to the value of 
coal where the first arm's-length sale is electricity is unnecessarily 
complicated and burdensome. While we disagree that the provisions in 
the 2017 Valuation Rule that would have capped oil and gas 
transportation allowances were arbitrary and capricious, we recognize 
that each cap would impose additional costs on some operators.
    Public Comment: ONRR received comments from industry trade groups 
stating that the 2017 Valuation Rule arbitrarily reversed a 
longstanding deep-water-gathering policy that permitted lessees to take 
transportation allowances for moving oil and gas production on the OCS.
    In contrast, a public interest group asserted the deep-water-
gathering policy allowed improper deductions under ONRR's regulatory 
scheme prior to the 2017 Valuation Rule. The commenter maintained that 
repealing the 2017 Valuation Rule removes language that ensures 
appropriate deep-water transportation allowances.
    ONRR Response: By repealing the 2017 Valuation Rule and reinstating 
the prior regulations, ONRR's longstanding deep-water-gathering policy 
will remain in effect, and ONRR will continue to implement it to the 
extent that it is consistent with the prior regulations. Nonetheless, 
ONRR believes that the deep-water-gathering policy is a matter that is 
appropriate to revisit and reconsider. ONRR will be further considering 
this matter, including through consultations as part of the RPC 
process.

I. Index-Based Gas Valuation Option

    The 2017 Valuation Rule added an index-price valuation method that 
lessees who do not sell their gas under an arm's-length sale could have 
elected to use in lieu of valuing their gas on their first arm's-length 
sale. ONRR based the method on publicly-available index prices, less a 
specified deduction to account for processing and transportation costs.
    Public Comment: An industry trade group and a member of the public 
cited the shortcomings in the index-based gas valuation option as one 
reason for repealing the 2017 Valuation Rule. While they supported the 
use of index-based valuation in concept, they argued that the index-
based valuation option in the rule is unreasonable and, at times, 
arbitrary for the following reasons: (1) ONRR did not provide the 
option to arm's-length lessees; (2) the index option could result in a 
price so high that it would disincentivize lessees from using it; (3) 
the adjustments for transportation and processing were too low; and (4) 
ONRR did not provide any standards for when and why it might change the 
adjustments.
    ONRR Response: We agree with the commenters that this is an area 
requiring further analysis. Given the mutual interest in exploring 
index-based valuation options, we believe the newly re-commissioned RPC 
will provide a valuable forum to engage our stakeholders in a 
meaningful way on this topic.

J. Percentage of Proceeds Contracts

    Lessees sometimes sell their gas under arm's-length length 
percentage-of-proceeds (POP) contracts for a price that is based on a 
specific percentage of the proceeds that the purchaser receives after 
processing the gas. The 2017 Valuation Rule required lessees with POP 
contracts to report and pay royalties as processed gas. This rule of 
repeal allows lessees to report and value POP contract sales as 
unprocessed gas.
    Public Comment: An industry trade group maintained that lessees 
would find it difficult to value gas sold under arm's-length POP 
contracts because they lack access to information from the midstream 
processors and/or purchasers.
    ONRR Response: Our experience is that the value lessees receive 
under a POP contract is usually net of certain costs incurred to place 
the gas into marketable condition. The 2017 Valuation Rule did not 
change the lessee's obligation to ensure that it is not deducting costs 
to place gas in marketable condition at no cost to the Federal 
government; repealing the rule likewise does not change that 
obligation. Nonetheless, we believe that how to value gas sold under 
arm's-length POP contracts is an appropriate topic for the RPC, and we 
look forward to engaging with members of the public and industry 
stakeholders to explore different options for reporting POP contracts.

K. Requirement of Written, Signed Contracts

    Although the 2017 Valuation Rule defined ``contract'' to include 
legally enforceable oral agreements, the rule itself required a lessee 
or its affiliate to have all of its contracts, contract revisions or 
amendments in writing and signed by all of the parties. If the lessee 
did not have a written contract, signed by all of the parties, then 
ONRR could use the default provision to determine value.
    Public Comment: Several commenters disagreed with the 2017 
Valuation Rule's requirement that all contracts for the sale, 
transportation, processing, or washing of oil, gas, or coal be in 
writing and signed by all parties to the contract. These commenters 
maintained that such a restriction ignores that unwritten and unsigned 
contracts are legally enforceable.
    ONRR Response: We adopted the requirement that all contracts be in 
writing and signed by all parties to enhance our ability to verify the 
accuracy of royalty reports and payments. For the reasons stated in the 
preamble to this rule, we reconsidered our position and now agree that 
this provision is unnecessary, overly burdensome, and potentially 
defective. The prior (and soon-to-be-reinstated) regulations do not 
require all contracts to be in writing and signed by all parties. But, 
under 30 CFR 1207.5, we will continue to require lessees to place in 
written form and maintain copies of all sales contracts and to maintain 
copies of other contracts and agreements for accounting or auditing 
purposes.

III. Procedural Matters

A. Summary Cost and Royalty Impact Data

    The economic impact analysis that we prepared in the 2017 Valuation 
Rule used 2010 royalty data. These economic impacts reflected market 
conditions--commodity price, volumes, etc.--that existed in 2010. In 
evaluating the economic impacts of repealing the rule, we used more 
recent royalty data. Using data from 2015 versus 2010 provides an 
estimate that is more in line with current market projections of future

[[Page 36944]]

commodity prices. The market for these resources changed between 2010 
and 2015, with the value of the resources generally decreasing. Not 
surprisingly, our updated analysis shows a somewhat smaller decrease in 
royalty payments compared to the analysis that accompanies the 2017 
Valuation Rule. Overall, our estimates for the previous rule, using 
2010 data, projected costs to industry of $74.78 million per year (with 
roughly corresponding benefits to the Treasury and States); this rule, 
using 2015 data, the projected costs to industry from the 2017 
Valuation Rule total $67.4 million per year; thus repeal of the rule 
results in $67.4 million in benefits to industry (with roughly 
corresponding benefits to the Treasury and States).
    We estimated the costs and benefits that this rule will have on all 
potentially affected groups: Industry, the Federal government, Indian 
lessors, and State and local governments. This repeal has cost impacts 
that will result in decreased royalty collections. The net impact of 
these provisions is an estimated annual decrease in royalty collections 
of between $60.1 million and $74.8 million. This represents between 0.8 
percent and 1.0 percent of the total Federal oil, gas, and coal 
royalties that we collected in 2015. Although the 2017 Valuation Rule 
was stayed before the first reporting and payments were due, some 
lessees had already implemented changes in their related systems and 
reporting procedures. Therefore, some lessees may incur additional 
costs from implementing this rule because some lessees may have to undo 
the system changes that they put in place in anticipation of first 
reporting under the 2017 Valuation Rule on February 28, 2017. We are 
unable to quantify that cost at this time.
    Unless otherwise indicated, the numbers in the following tables are 
rounded to three significant digits.
1. Industry
    The table below lists ONRR's itemized low, mid-range, and high 
estimates of the costs and benefits that industry would incur in the 
first year. Industry would receive these benefits in the same amount 
each year thereafter.

                                     Summary of Royalty Impacts to Industry
----------------------------------------------------------------------------------------------------------------
                         Rule provision                                 Low             Mid            High
----------------------------------------------------------------------------------------------------------------
Gas--restore benchmarks:
    Remove affiliate resale.....................................              $0      $1,360,000      $2,710,000
    Remove index................................................      10,600,000      10,600,000      10,600,000
NGLs--restore benchmarks:
    Remove affiliate resale.....................................               0         754,000       1,510,000
    Remove index................................................     (2,210,000)     (2,210,000)     (2,210,000)
Gas transportation 50 percent limitation exceptions reinstated..          87,000          87,000          87,000
Processing allowance 66\2/3\ percent limitation exceptions                42,700          42,700          42,700
 reinstated.....................................................
POP contracts processing allowance exceptions of 66\2/3\ percent       9,470,000       9,470,000       9,470,000
 reinstated.....................................................
Extraordinary processing allowance reinstated...................      14,200,000      14,200,000      14,200,000
Deep-water-gathering reinstated.................................      23,900,000      28,100,000      32,300,000
Oil transportation 50 percent limitation exceptions reinstated..               0               0               0
Oil and gas line losses allowance reinstated....................       3,140,000       3,140,000       3,140,000
BBB bond rate change removed....................................       5,740,000       5,740,000       5,740,000
Coal--non-arm's-length netback reinstated.......................     (1,030,000)               0       1,030,000
Removing index option administrative costs......................       (303,000)       (303,000)       (303,000)
Removing deep-water-gathering administrative costs..............     (3,560,000)     (3,560,000)     (3,560,000)
                                                                 -----------------------------------------------
    Total.......................................................      60,100,000      67,400,000      74,800,000
----------------------------------------------------------------------------------------------------------------
Note: totals from this table and others in this analysis may not add due to rounding.

Benefit--Reinstatement of the Valuation Benchmarks for Non-Arm's-Length 
Dispositions of Federal Unprocessed Gas, Residue Gas, and Coalbed 
Methane
    To perform this economic analysis, we first extracted royalty data 
that we collected on residue gas, unprocessed gas, and coalbed methane 
(product codes 03, 04, and 39, respectively) for calendar year 2015. We 
did not include 2016 in any of our data sets because lessees are still 
adjusting their reports for that year and the reported data is still 
going through ONRR's edits.
    We then extracted gas royalty data for non-arm's-length 
transactions reported with the sales type code NARM. We also extracted 
gas royalty data for sales type code POOL because royalty reporters may 
also use this code to report certain non-arm's-length transactions. 
Based on our experience with auditing transactions that use sales type 
code POOL, only a relatively small portion of transactions are non-
arm's-length. Therefore, we used 10 percent of the POOL volumes in our 
economic analysis of the volumes of gas sold at non-arm's length.
    Based on our experience auditing production sold under non-arm's-
length contracts, we find that industry would incur a royalty decrease 
between $0.00 and $0.05 per MMBtu under our proposal to use the 
benchmarks instead of the affiliate's first arm's-length resale to 
value gas production for royalty purposes. We address the royalty 
impact of the index-based option below.
    We generated a range of potential royalty decreases by assuming no 
change in royalties for the low estimate, $0.025 per MMBtu for the mid-
range estimate, and $0.05 per MMBtu for the high estimate. We then 
multiplied the NARM volume and 10 percent of the POOL volume reported 
to ONRR in 2015 by the potential royalty decrease.
    The results below are an estimated benefit to industry due to an 
annual royalty decrease of between zero and approximately $5.4 million. 
We reduced this estimate by one-half and assumed the mid-point of 
$0.025 totaling $1.36 million. This assumes that 50 percent of the 
lessees selling production under non-arm's-length arrangements would 
have chosen this option under the 2017 Valuation Rule.

[[Page 36945]]



----------------------------------------------------------------------------------------------------------------
                                                                               Royalty decrease ($)
                                               2015 MMBtu volume -----------------------------------------------
                                                 (non-rounded)      Low ($0.00)    Mid  ($0.025)   High ($0.05)
----------------------------------------------------------------------------------------------------------------
NARM volume..................................         97,869,053              $0      $2,446,726      $4,893,453
10% POOL volume..............................         10,614,876               0         265,372         530,744
                                              ------------------------------------------------------------------
    Total....................................        108,483,929               0       2,712,098       5,424,196
                                              ------------------------------------------------------------------
50% of lessees choose this option............  .................               0       1,360,000       2,710,000
----------------------------------------------------------------------------------------------------------------

Benefit--Termination of the Index-Based Option To Value Non-Arm's-
Length Sales of Federal Unprocessed Gas, Residue Gas, and Coalbed 
Methane
    To estimate the royalty impact of removing the index-based option, 
we calculated a monthly weighted average price net of transportation 
using NARM and 10 percent of the POOL gas royalty data from seven major 
geographic areas with active index prices: The Green River Basin, San 
Juan Basin, Piceance and Uinta Basins, Powder River Basin, Wind River 
Basin, Permian Basin, and Offshore Gulf of Mexico (GOM). These areas 
account for approximately 95 percent of all Federal gas produced. To 
calculate the estimated impact, we performed the following steps: 
First, identified the Platts Inside FERC highest reported monthly price 
for the index price applicable to each area--Northwest Pipeline Rockies 
for Green River, El Paso San Juan for San Juan, Northwest Pipeline 
Rockies for Piceance and Uinta, Colorado Interstate Gas for Powder 
River and Wind River, El Paso Permian for Permian, and Henry Hub for 
GOM. Second, we subtracted the transportation deduction that we 
specified in the 2017 Valuation Rule from the highest index price that 
we identified in the first step. Third, we subtracted the average 
monthly net royalty price reported to us for unprocessed gas from the 
highest index price for the same month that we calculated in the second 
step. Fourth, we then multiplied the royalty volume by the monthly 
difference that we calculated in the third step to calculate a monthly 
royalty difference for each region. And fifth, we totaled the 
difference that we calculated in the fourth step for the regions.
    In 2015, the estimated royalties due using the index-based option 
was greater than the reported royalties in every month during our 
analysis.
    We estimate the benefit to industry due to this change to be a 
decrease in royalty payments of approximately $10.6 million annually. 
This estimate represents an average decrease of approximately 9.8 
percent, or $0.026 per MMBtu, based on an annual royalty volume of 
154,104,793 MMBtu (for NARM and 10 percent POOL reported sales type 
codes). This would have been the first time that we offered this 
option; therefore, we did not know how many payors would choose it. We 
reduced this estimate by one-half, assuming that 50 percent of lessees 
with non-arm's-length sales would have chosen this option.

----------------------------------------------------------------------------------------------------------------
                                                                      GOM gas        Other gas         Total
----------------------------------------------------------------------------------------------------------------
2015 royalties..................................................     $72,216,537    $143,618,273    $215,834,810
Royalty under index option......................................      79,359,207     157,684,860     237,044,067
Difference......................................................       7,142,670      14,066,587      21,209,257
Per unit change ($/MMBtu).......................................           0.030           0.025           0.026
% Change........................................................            9.9%            9.8%            9.8%
50% of lessees choose this option...............................  ..............  ..............      10,600,000
----------------------------------------------------------------------------------------------------------------

Benefit--Reinstatement of the Valuation Benchmarks for Non-Arm's-Length 
Dispositions of Federal NGLs
    Like the valuation changes that we discussed previously, for 
Federal unprocessed, residue, and coalbed methane gas valuation, this 
rule will value processed Federal NGLs under the prior valuation 
benchmarks rather than either (1) tracing the first arm's-length sale 
or (2) using the index-based option discussed previously. Lessees will 
no longer have the option to value royalties using an index price value 
derived from an NGL commercial price bulletin less a theoretical 
processing allowance that included theoretical transportation and 
fractionation of the NGLs. We again used the 2015 NARM and POOL NGL 
data that lessees reported to ONRR for this analysis.
    We performed the same analysis for valuation using the first arm's-
length sale for Federal unprocessed, residue, and coalbed methane gas, 
as we discussed. We identified the non-arm's-length volumes that would 
qualify for this option (for NARM and 10 percent POOL reported sales 
type codes) and estimated a cents-per-gallon royalty decrease. Based on 
our experience, we estimate that the NGL resale margin, similar to gas, 
would range from zero to $0.03 per gallon. Thus, our estimated royalty 
decrease is zero for the low, $0.015 per gallon for the mid-range, and 
$0.03 per gallon for the high range. The results below show a mid-range 
decrease of $754,000 in royalty obligations using these assumptions, 
and, again, we reduced them by one-half under the assumption that 50 
percent of lessees would have chosen this option.

----------------------------------------------------------------------------------------------------------------
                                                   2015 gallons                Royalty decrease ($)
                                                    (rounded to  -----------------------------------------------
                                                    the nearest     Low ($0.00
                                                      gallon)         cents)        Mid ($0.15)    High ($0.03)
----------------------------------------------------------------------------------------------------------------
NARM volume.....................................      66,911,096              $0      $1,003,666      $2,007,333

[[Page 36946]]

 
10% of POOL volume..............................      33,675,717               0         505,136       1,010,272
                                                 ---------------------------------------------------------------
    Total.......................................     100,586,813               0       1,508,802       3,017,604
----------------------------------------------------------------------------------------------------------------
50% of lessees choose this option...............  ..............               0         754,000       1,510,000
----------------------------------------------------------------------------------------------------------------

Cost--Termination of the Index-Based Option To Value Non-Arm's-Length 
Dispositions of Federal NGLs
    Like the Federal unprocessed, residue, and coalbed methane gas 
changes that we discussed, lessees will no longer have the option to 
pay royalties on Federal NGLs production using an index-based value, 
less a theoretical processing allowance that includes transportation 
and fractionation. We used the same 2015 NARM and POOL transaction data 
for NGLs for this analysis. We were unable to compare NGL prices 
reported on the form ONRR-2014 to those in commercial price bulletins 
because the prices that lessees report on the form ONRR-2014 are a 
single rolled-up price for all NGLs and the bulletins price each NGL 
product (such as ethane and propane) separately. Therefore, we 
calculated a weighted price, or basket price, from the published prices 
based on typical NGL product volumes, as well as based our analysis on 
the royalty changes that result from removal of the theoretical 
processing allowance provided under this option.

----------------------------------------------------------------------------------------------------------------
                                                                     GOM NGLs       Other NGLs         Total
----------------------------------------------------------------------------------------------------------------
2015 royalties..................................................     $22,292,763      $9,884,982     $32,177,746
Royalty under index option......................................     $20,165,669      $7,585,605     $27,751,273
Difference......................................................    ($2,127,095)    ($2,299,378)    ($4,426,472)
Per-unit change ($/gal).........................................        ($0.004)        ($0.008)        ($0.006)
Percent change..................................................           -9.5%          -23.3%          -13.8%
50% of lessees choose this option...............................  ..............  ..............    ($2,210,000)
----------------------------------------------------------------------------------------------------------------

Cost--Termination of the Index-Based Option To Value Non-Arm's-Length 
Federal Unprocessed Gas, Residue Gas, Coalbed Methane, and NGLs
    ONRR expects that industry will incur additional administrative 
costs from losing the option to use the index-based option to value 
non-arm's-length dispositions of Federal unprocessed gas, residue gas, 
coalbed methane, and NGLs. Lessees will have to calculate the value of 
their production using the valuation benchmarks, increasing the time 
that it takes to calculate the correct price. Lessees will also have to 
calculate their specific transportation rate for gas, and processing 
allowance for NGLs, rather than using the ONRR-specified theoretical 
values.
    For the 50 percent of lessees that we estimated would use this 
option, we estimate that eliminating the index-based option will 
increase the time burden per line reported by 50 percent to 1.5 minutes 
for lines that industry electronically submits and 3.5 minutes for 
lines that they manually submit. In 2015, ONRR received approximately 
16 percent more lines than from the data used in the prior rule. We 
used tables from the Bureau of Labor Statistics (BLS) (https://www.bls.gov/oes/current/oes132011.htm#nat), which we updated to use 
current BLS data to estimate the hourly cost for industry accountants 
in a metropolitan area. We added a multiplier of 1.4 for industry 
benefits. The industry labor cost factor for accountants will be 
approximately $53.42 per hour = $38.16 [mean hourly wage] x 1.4 
[benefits cost factor]. Using a labor cost factor of $53.42 per hour, 
we estimate that the annual administrative cost to industry will be 
approximately $303,000.

----------------------------------------------------------------------------------------------------------------
                                                                                     Estimated
                                                                Time burden per   lines reported   Annual burden
                                                                 line reported      using index        hours
                                                                     (min)         option (50%)
----------------------------------------------------------------------------------------------------------------
Electronic reporting (99%)...................................                1.5         221,780           5,544
Manual reporting (1%)........................................                3.5           2,240             131
Industry labor cost/hour.....................................  .................  ..............          $53.42
                                                              --------------------------------------------------
    Total cost to industry...................................  .................  ..............        $303,000
----------------------------------------------------------------------------------------------------------------

Benefit--Allow Transportation Allowances in Excess of 50 Percent of the 
Value of Federal Gas
    Prior to the 2017 Valuation Rule, the Federal gas valuation 
regulations limited lessees' transportation allowances to 50 percent of 
the value of the gas unless they requested and received approval to 
exceed that limit. The 2017 Valuation Rule eliminated the lessees' 
ability to exceed that limit. This rule reinstates the lessees' ability 
to request and receive approval to exceed the 50 percent limitation. To 
estimate the impacts associated with this change, we first identified 
all calendar year 2015 reported gas transportation allowances rates 
that exceeded the 50-percent limit. We then adjusted those allowances 
down to the 50-percent limit and totaled that value to estimate the 
economic impact of this provision. The result was an annual estimated 
benefit to industry of $87,000.

[[Page 36947]]

Benefit--Allow Transportation Allowances in Excess of 50 Percent of the 
Value of Federal Oil
    Prior to the 2017 Valuation Rule, the Federal oil valuation 
regulations limited lessees' transportation allowances to 50 percent of 
the value of the oil unless they requested and received approval to 
exceed that limit. The 2017 Valuation Rule eliminated the lessees' 
ability to exceed that limit. This rule reinstates the lessees' ability 
to request and receive approval to exceed the 50-percent limitation. To 
estimate the costs associated with this change, we searched for 
calendar year 2015-reported oil transportation allowance rates that 
exceeded the 50-percent limit. We did not find any lines for oil 
transportation that exceeded the 50 percent, so there will be no impact 
to industry. But companies may exceed the 50-percent limit in the 
future.
Benefit--Allow Processing Allowances in Excess of 66\2/3\ Percent of 
the Value of the NGLs for Federal Gas
    Prior to the 2017 Valuation Rule, the Federal gas valuation 
regulations limited lessees' processing allowances to 66\2/3\ percent 
of the value of the NGLs unless they requested and received approval to 
exceed that limit. The 2017 Valuation Rule eliminated lessees' ability 
to exceed that limit. This rule reinstates the lessees' ability to 
request and receive approval to exceed the 66\2/3\-percent limitation. 
To estimate the cost to industry associated with this change, we first 
identified all calendar year 2015-reported processing allowances 
greater than 66\2/3\ percent. We then adjusted those allowances down to 
the 66\2/3\-percent limit and totaled that value to estimate the 
economic impact of this provision. The result was an annual estimated 
benefit to industry of $42,700.
Benefit--Arm's-Length POP Contracts Not Subject to the 66\2/3\ Percent 
Processing Allowance Limit for Federal Gas
    In this rule and the rule in effect prior to the 2017 Valuation 
Rule, lessees with POP contracts paid royalties based on their gross 
proceeds as long as they paid a minimum value equal to 100 percent of 
the value of the residue gas. Under the 2017 Valuation Rule, we do not 
allow lessees with POP contracts to deduct more than the 66\2/3\ 
percent of the value of the NGLs. This rule reinstates the previous 
regulation's provision allowing lessees with POP contracts to pay 
royalties based on their gross proceeds, as long as those gross 
proceeds are, at a minimum, equal to 100 percent of the value of the 
residue gas. For example, a lessee with a 70-percent POP contract 
receives 70 percent of the value of the residue gas and 70 percent of 
the value of the NGLs. The 30 percent of each product that the lessee 
gives up to the processing plant in the past could not, when combined, 
exceed an equivalent value of 100 percent of the NGLs' value. By 
repealing the 2017 Valuation Rule, the combined value of each product 
that the lessee gives up to the processing plant could, again, 
potentially exceed two-thirds of the NGLs' value.
    Lessees report POP contracts to ONRR using sales type codes APOP 
for arm's-length POP contracts and NPOP for non-arm's-length POP 
contracts. Because lessees report arm's-length POP contract sales as 
unprocessed gas, there are no reported processing allowances for us to 
analyze, and we cannot determine the breakout between residue gas and 
NGLs. Lessees do report residue gas and NGLs separately for non-arm's-
length POP contracts. However, these reported volumes constitute only 
0.07 percent of all the natural gas royalty volumes reported to ONRR. 
We deemed the non-arm's-length POP volume to be too low to adequately 
assess the impact of this provision on both arm's-length POP and non-
arm's-length POP contracts.
    Therefore, we examined all reported calendar year 2015 onshore 
residue gas and NGLs royalty data and assumed that it was processed and 
that lessees paid royalties as if they sold the residue gas and NGLs 
under a POP contract. We restricted our analysis to residue gas and NGL 
volumes produced onshore because we are not aware of any offshore POP 
contracts. We first totaled the residue gas and NGLs' royalty value for 
calendar year 2015 for all onshore royalties. We then assumed that 
these royalties were subject to a 70-percent POP contract. Based on our 
experience, a 70/30 split is typical for many POP contracts. We 
calculated 30 percent of both the value of residue gas and the NGLs to 
approximate a theoretical 30-percent processing deduction. We then 
compared the 30-percent total of residue gas and NGLs values to 66\2/3\ 
percent of the NGLs value (the maximum allowance under the 2017 
Valuation Rule). The table below summarizes these calculations, which 
we rounded to the nearest dollar:

----------------------------------------------------------------------------------------------------------------
                                                   2015 royalty
                                                  value prior to                70%                     30%
                                                     allowances
----------------------------------------------------------------------------------------------------------------
Residue gas.....................................    $494,401,673                    $346,081,171    $148,320,502
NGLs............................................     132,618,537                      92,832,976      39,785,561
                                                 ---------------------------------------------------------------
    Total.......................................     627,020,209                     438,914,147     188,106,063
                                                 ---------------------------------------------------------------
66.67% limit....................................      88,412,358           (132,618,537 x \2/3\)
Difference......................................      99,693,705    ($188,106,063 - $88,412,357)
----------------------------------------------------------------------------------------------------------------

    Our analysis shows that the theoretical processing deduction for 30 
percent of the value of residue gas and NGLs ($188 million) under our 
assumed onshore POP contract allowance would exceed the 66\2/3\ cap 
($88 million) under this rule.
    In our analysis for the 2017 Valuation Rule, the theoretical 
deduction did not exceed the allowance cap, and we estimated that this 
change would result in no impact. The 2015 data, however, did show that 
the theoretical deduction exceeded the allowance cap, and there will be 
an economic impact by repealing the 2017 Valuation Rule. This is 
primarily due to the changing price relationship between gas and NGLs.
    We estimated that the benefit to industry would be $9.47 million by 
taking the royalty value that exceeds the POP contract allowance ($100 
million) and dividing by the total of non-POP volume (1,582,143,530 
MMBtu) to calculate a per-MMBtu rate of $0.06. We then applied the 
$0.06 rate to the POP contract total volume of 157,764,948 MMBtu to get 
the estimated increase of $9.47 million. For the sake of this analysis, 
we assumed that all processing costs incurred were allowable.

[[Page 36948]]



----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
2015 MMBtu volume...............................................   1,582,143,530
Rate/MMBtu over limit...........................................           $0.06     ($99,693,705/1,582,143,530)
POP MMBtu volume................................................     157,764,948
Total impact to industry........................................      $9,470,000            ($.06 x 157,764,948)
----------------------------------------------------------------------------------------------------------------

Benefit-- Reinstatement of Policy Allowing Transportation Allowances 
for Deep-Water-Gathering Systems for Federal Oil and Gas
    The deep-water-gathering policy discussed previously allows 
companies to deduct certain expenses for subsea gathering from their 
royalty payments, even though those costs do not meet ONRR's definition 
of transportation. This rule would result in ONRR continuing to apply 
the policy to the extent that it is consistent with the prior (and 
soon-to-be-reinstated) regulations. Lessees would therefore be allowed 
to claim additional allowances, which would decrease their royalties 
due. To analyze the impact to industry of reinstating this policy, we 
used data from BSEE's ArcGIS TIMS (Technical Information Management 
System) database to estimate that 113 subsea pipeline segments serving 
140 leases currently qualify for an allowance under the policy. We 
assumed all segments were the same--in other words, we did not take 
into account the size, length, or type of pipeline. For our analysis we 
also considered only pipeline segments that were in active status and 
leases in producing status. To determine a range (shown in the tables 
below as low, mid, and high estimates) for the impact for industry, 
ONRR estimated a 15 percent error rate in our identification of the 113 
eligible pipeline segments, resulting in a range of 96 to 130 eligible 
pipeline segments.
    Historical ONRR audit data was available for 13 subsea gathering 
segments, which served 15 leases covering time periods from 1999 
through 2010. We used this data to determine an average initial amount 
of capital investment in pipeline segments. We used the initial capital 
investment amount to calculate depreciation and a return on 
undepreciated capital investment (ROI) for the eligible pipeline 
segments. We calculated depreciation using a straight-line depreciation 
schedule based on a 20-year useful life of the pipeline. We calculated 
ROI using 1.0 times the average BBB Bond rate for January 2012, which 
was the most recent full month of data at the time we performed this 
analysis. We based the calculations for depreciation and ROI on the 
first year a pipeline was in service.
    From the same audit data, we calculated an average annual operating 
and maintenance (O&M) cost. We increased the O&M cost by 12 percent to 
account for overhead expenses. Based on experience and audit data, we 
assumed that 12 percent is a reasonable increase for overhead. We then 
decreased the total annual O&M cost per pipeline segment by nine 
percent because an average of nine percent of offshore wellhead oil and 
gas production is water, which is not royalty bearing. Finally, we used 
an average royalty rate of 14 percent, which is the volume weighted 
average royalty rate for all non-Section 6 leases in the Gulf of 
Mexico. Based on the these calculations, the average annual allowance 
per pipeline segment is approximately $226,664. This represents the 
estimated amount per pipeline segment ONRR would no longer allow 
lessees to take as a transportation allowance based on our rescission 
of the Deep Water Policy in this proposed rulemaking.
    The total cost to industry would be the $226,664 annual allowance 
per pipeline segment that we would allow under this proposed rulemaking 
times the number of eligible segments. To calculate a range for this 
total, we multiplied the average annual allowance by the low (96), mid 
(113), and high (130) number of eligible segments. The low, mid, and 
high annual allowance estimates we would allow are $21.8 million, $25.6 
million, and $29.5 million, respectively.
    Of the currently eligible leases, 56 out of 140, or about 40 
percent, qualified for deep water royalty relief under the policy. 
However, due to varying lease terms, royalty relief programs, price 
thresholds, volume thresholds, litigation, and other factors, ONRR 
estimated that only one-half of the 56 leases eligible for royalty 
relief (20 percent of the 56) actually received royalty relief. 
Therefore, we decreased the low, mid, and high estimated annual benefit 
to industry by 20 percent. The table below shows the estimated royalty 
impact of this section of the proposed rule based on the allowances we 
will allow under this rule.

----------------------------------------------------------------------------------------------------------------
                                                                     Low              Mid              High
----------------------------------------------------------------------------------------------------------------
Estimated Royalty Impact.....................................     $23,900,000      $28,100,000      $32,300,000
----------------------------------------------------------------------------------------------------------------

Cost--Reinstatement of Policy Allowing Transportation Allowances for 
Deep-Water- Gathering Systems for Federal Oil and Gas
    We estimate the restoration of transportation allowances for deep-
water-gathering systems would eliminate the industry administrative 
benefit under the 2017 Valuation Rule as lessees would have to perform 
this calculation. We assume that the cost to perform this calculation 
is significant because in our experience industry has often hired 
outside consultants to calculate their subsea transportation 
allowances. Using this information, we estimate each company with 
leases eligible for transportation allowances for deep water gathering 
systems would allocate one full-time FTE annually to perform this 
calculation, whether they use consultants or perform the calculation 
in-house. We used the Bureau of Labor Statistics to estimate the hourly 
cost for industry accountants in a metropolitan area ($38.16 mean 
hourly wage) with a multiplier of 1.4 for industry benefits to equal 
approximately $53.42 per hour ($38.16 x 1.4). Using this labor cost per 
hour, we estimate the annual administrative cost to industry would be 
approximately:

[[Page 36949]]



 
----------------------------------------------------------------------------------------------------------------
                                                                                   Companies
                                               Annual  burden  Industry  labor     reporting     Estimated  cost
                                                 hours per         cost/hour        eligible       to  industry
                                                  company                            leases
----------------------------------------------------------------------------------------------------------------
Deep Water Gathering........................           2,080           $53.42               32       $3,560,000
----------------------------------------------------------------------------------------------------------------

Benefit--Reinstating Extraordinary Processing Cost Allowances for 
Federal Gas
    As we discussed previously, we are reinstating the provision in our 
regulations that allows lessees to request an extraordinary processing 
cost allowance and to allow any extraordinary processing cost 
allowances that we previously granted. We have granted two such 
approvals in the past, so we know the lease universe that is claiming 
this allowance and were able to retrieve the processing allowance data 
that lessees deducted from the value of residue gas produced from the 
leases. We then calculated the annual total processing allowance that 
lessees have claimed for 2012 through 2015 for the leases at issue. We 
then averaged the yearly totals for those four years to estimate an 
annual benefit to industry of $14.2 million in decreased royalties.
Benefit--Increasing the Rate of Return Used To Calculate Non-Arm's-
Length Transportation Allowances From 1 to 1.3 Times the Standard and 
Poor's BBB Bond for Federal Oil and Gas
    For Federal oil transportation, we do not maintain or request data 
identifying whether transportation allowances are arm's length or non-
arm's length. However, in our experience, lessees transport a 
significant portion of Gulf of Mexico (GOM) oil through their own 
pipelines. In addition, many onshore transportation allowances include 
costs of trucking and rail and, most likely, this change would not 
impact those. Therefore, to calculate the costs associated with this 
change, we assumed that 50 percent of the GOM transportation allowances 
are non-arm's length and that ten percent of transportation allowances 
everywhere else (onshore and offshore other than the GOM) are non-arm's 
length. We also assumed that, over the life of the pipeline, allowance 
rates are made up of one-third rate of return on undepreciated capital 
investment, one-third depreciation expenses, and one-third operation, 
maintenance, and overhead expenses.
    In 2015, the total oil transportation allowances that Federal 
lessees deducted were approximately $100 million from the GOM and $12.5 
million from everywhere else. Based on these totals and our assumptions 
regarding the makeup of the allowance components, the portion of the 
non-arm's-length allowances attributable to the rate of return will be 
approximately $16,600,000 for the GOM ($100,000,000 x \1/3\ x 50%) and 
$416,000 ($12,500,000 x \1/3\ x 10%) for the rest of the country. Based 
on these assumptions, industry will receive an increase in yearly oil 
transportation allowance deductions of approximately $3,920,000 
($17,000,000 x (1.3 - 1.0)/1.3). That is, we estimate that the net 
benefit to industry for oil transportation allowances as a result of 
this change will be an approximately $3,920,000 in decreased royalties 
due.
    Like Federal oil, we do not maintain or request information on 
whether Federal gas transportation allowances are arm's-length or non-
arm's length. However, unlike Federal oil, in our experience, it is not 
common for GOM gas to be transported through lessee-owned pipelines. 
Therefore, we assumed that only 10 percent of all gas transportation 
allowances are non-arm's length and made no distinction between the GOM 
and everywhere else. All other assumptions for natural gas are the same 
as those that we made for oil.
    In 2015, the total gas transportation allowances that Federal 
lessees deducted were approximately $238 million. Based on that total 
and our assumptions regarding the makeup of the allowance components, 
the portion of the non-arm's-length allowances attributable to the rate 
of return will be approximately $7.93 million ($238,000,000 x \1/3\ x 
10%). Therefore, industry will see an increase in yearly gas 
transportation allowance deductions of approximately $1.82 million 
($7.93 million x (1.3 - 1.0)/1.3). That is, the net decreased cost to 
industry for gas transportation allowances will be approximately 
$1,820,000.
    The combined impact to industry for this change will be $5,740,000 
in decreased royalties due.
No Change--Disallow a Rate of Return on Reasonable Salvage Value for 
Federal Oil, Gas, and Coal
    In the 2017 Valuation Rule, ONRR estimated that this provision 
would have no impact to industry. ONRR likewise estimates that the 
repeal has no impact.
Benefit--Allow Line Loss as a Component of Non-Arm's-Length Oil and Gas 
Transportation
    This rule also reinstates the regulatory provision allowing lessees 
to deduct the costs of pipeline losses, both actual and theoretical, 
when calculating non-arm's-length transportation allowances. For this 
analysis, we assumed that pipeline losses are 0.2 percent of the volume 
transported through the pipeline, based on a survey of pipeline tariff. 
This 0.2 percent of the volume transported would also equate to 0.2 
percent of the value of the Federal royalty volume of oil and gas 
production transported.
    For Federal oil produced in calendar year 2015, the Federal royalty 
value subject to transportation allowances was $2,746,256,148 in the 
GOM and $1,039,271,142 everywhere else. Using our previous assumption 
that 50 percent of GOM and 10 percent of everywhere else's 
transportation allowances are non-arm's length, we estimated that the 
value of the line loss will be $2.96 million, as we detailed in the 
table below. Therefore, the annual benefit to industry will be 
approximately $2.96 million.

                                          Oil Line Loss Royalty Impact
----------------------------------------------------------------------------------------------------------------
                                                                                                      Royalty
                                                                                   Line loss  %      decrease
----------------------------------------------------------------------------------------------------------------
50% of GOM royalty value......................................    $1,373,128,209             0.2      $2,750,000
10% of everywhere else royalty value..........................       103,927,114             0.2         208,000
                                                               -------------------------------------------------

[[Page 36950]]

 
    Total.....................................................  ................  ..............       2,960,000
----------------------------------------------------------------------------------------------------------------

    For Federal gas produced in calendar year 2015, the Federal gas 
royalty value subject to transportation allowances was $888,676,828. 
Using our previous assumption that 10 percent of Federal gas 
transportation allowances are non-arm's length, we estimated that the 
value of the line loss and annual benefit to industry would be 
$178,000.

                                          Gas Line Loss Royalty Impact
----------------------------------------------------------------------------------------------------------------
                                                                                                     Royalty
                                                                                  Line loss  %       decrease
----------------------------------------------------------------------------------------------------------------
10% of royalty value.......................................       $88,867,683              0.2         $178,000
----------------------------------------------------------------------------------------------------------------

    The total estimated royalty decrease for both oil and gas due to 
this change will be $3.14 million [$2,960,000 (oil) plus $178,000 (gas) 
= $3,140,000].
Benefit--Depreciating Oil Pipeline Assets Only Once
    Under the non-arm's-length transportation allowance section of this 
rule and the rule in effect prior to the 2017 Valuation Rule, for 
Federal oil, if an oil pipeline is sold, the purchasing company might 
use the purchase price to establish a new depreciation schedule, 
provided that the purchasing company is a royalty payor claiming a non-
arm's-length transportation allowance. In theory, this change results 
in additional royalty savings for companies. However, based on our 
experience monitoring the oil markets, we find that the sale of oil 
pipeline assets is rare. We are also not aware of any planned future 
sales of oil pipelines that this rule change will impact. Therefore, 
although there will be a benefit to industry under this rule, we cannot 
quantify the cost at this time.
No Change--Eliminating the Use of the First Arm's-Length Sale to Value 
Non-Arm's-Length Sales of Federal Coal and Sales of Federal Coal 
Between Parties That Lack Opposing Economic Interest--``Coal 
Cooperatives'' in the 2017 Valuation Rule
    In the 2017 Valuation Rule, ONRR did not estimate any impacts to 
industry for the change in regulations for this provision. This repeal 
will reinstate the valuation regulations as they were prior to the 2017 
Valuation Rule's publication. Therefore, ONRR does not estimate any 
impact to industry at this time.
No Change--Eliminating the Use of Arm's-Length Electricity Sales to 
Value Non-Arm's-Length Dispositions of Federal Coal and Dispositions of 
Federal Coal Parties That Lack Opposing Economic Interest--``Coal 
Cooperatives'' in the 2017 Valuation Rule
    In the 2017 Valuation Rule, ONRR did not estimate any impacts to 
industry for the change in regulations for this provision. This repeal 
will reinstate the valuation regulations as they were prior to the 2017 
Valuation Rule's publication. Therefore, ONRR does not estimate any 
impact to industry at this time.
No Change--Eliminating the Default Provision to Value Non-Arm's-Length 
Sales of Federal Coal in Lieu of Sales of Electricity
    For these situations, valuation of Federal coal will be determined 
under the non-arm's-length benchmarks after this repeal of the 2017 
Valuation Rule. Because the default provision establishes a valuation 
method that approximates the market value of the coal very similar to 
the benchmarks, we estimate that the royalty effect of this rule on 
lessees of Federal coal will be nominal.
No Change--Using the First Arm's-Length Sale to Value Non-Arm's-Length 
Sales of Indian Coal
    In the 2017 Valuation Rule, ONRR did not estimate any impacts to 
industry for the change in regulations for this provision. This repeal 
will reinstate the valuation regulations as they were prior to the 2017 
Valuation Rule's publication. Therefore, we do not estimate any impact 
to industry at this time.
No Change--Using Sales of Electricity to Value Non-Arm's-Length Sales 
of Indian Coal
    In the 2017 Valuation Rule, ONRR did not estimate any impacts to 
industry for the change in regulations for this provision. This repeal 
will reinstate the valuation regulations as they were prior to the 2017 
Valuation Rule's publication. Therefore, we do not estimate any impact 
to industry at this time.
No Change--Using First Arm's-Length Sale to Value Sales of Indian Coal 
Between Coal Cooperative Members
    In the 2017 Valuation Rule, ONRR did not estimate any impacts to 
industry for the change in regulations for this provision. This repeal 
will reinstate the valuation regulations as they were prior to the 2017 
Valuation Rule's publication. Therefore, we do not estimate any impact 
to industry at this time.
No Change--Elimination of the Default Provision to Value Federal Oil, 
Gas, and Coal and Indian Coal
    In the 2017 Valuation Rule, we anticipated that we would have used 
the default provision only in specific cases where conventional 
valuation procedures have not worked to establish a value for royalty 
purposes. We also stated that assigning a royalty impact figure to any 
of the instances where we would have used the default provisions was 
speculative because (1) each instance would have been case-specific, 
(2) we could not anticipate when we would have used the option, and (3) 
we could not anticipate the value that we would have required companies 
to pay. Additionally, we estimated that the royalty impact would have 
been relatively small because the default provision would always have 
established a reasonable value of

[[Page 36951]]

production using market-based transaction data, which has always been 
the basis for our royalty valuation rules. Therefore, removal of the 
default provision will have a similarly small and speculative royalty 
difference.
2. State and Local Governments
    We estimate that the States and local governments that this rule 
impacts will incur a decrease in royalty receipts. The details of this 
impact are outlined below.
    States and local governments receiving revenues for offshore Outer 
Continental Shelf Lands Act Section 8(g) leases will continue to 
receive royalties as under the regulations preceding the 2017 Valuation 
Rule, as will States receiving revenues from onshore Federal lands. 
Based on the ratio of Federal revenues disbursed to States and local 
governments for section 8(g) leases and the onshore States we detail in 
the table below, ONRR assumed the same proportion of revenue decreases 
for each proposal that will impact those State revenues for most of the 
provisions.

                   Royalty Distributions by Lease Type
------------------------------------------------------------------------
                                               Onshore  Offshore   8(g)
                                                   %        %        %
------------------------------------------------------------------------
Federal......................................       50       100      73
State........................................       50         0       0
Section 8(g).................................        0         0      27
------------------------------------------------------------------------

    Some provisions of this rule affect Federal, State, and local 
government revenues, while others, such as reinstating extraordinary 
processing cost allowances, affect only onshore States' and Federal 
revenues. The table summarizing the State and local government royalty 
decreases that we provide in section 5 details these differences.
3. Indian Lessors
    ONRR estimates that the changes to the coal regulations that apply 
to Indian lessors will have no impact on their royalties.
4. Federal Government
    The impact to the Federal government, like the States and local 
governments, will be a net decrease in royalties as a result of these 
changes. The royalty decrease incurred by the Federal government will 
be the difference between the total royalty decrease to industry and 
the royalty decrease affecting the States and local governments. The 
net yearly impact on the Federal government will be approximately $55.8 
million, which we detail in section (5) below.
5. Summary of Royalty Impacts and Costs to Industry, State and Local 
Governments, Indian Lessors, and the Federal Government
    In the table below, the negative values in the industry column 
represent their estimated royalty collection decrease for Federal, 
State, and local governments, while the positive values in the other 
columns represent the increase in royalty savings for industry. Please 
note that the estimated impacts to Federal, State, and local 
governments do not include the administrative savings provisions of the 
economic analysis discussed above. Those provisions are only realized 
by industry. For the purposes of this summary table, we used the 
midpoint estimates for these impacts.

----------------------------------------------------------------------------------------------------------------
                 Rule Provision                      Industry         Federal          State        State 8(g)
----------------------------------------------------------------------------------------------------------------
Gas--restore benchmarks:
    Remove affiliate Resale.....................      $1,360,000      ($865,000)      ($483,000)       ($11,600)
    Remove index................................     $10,600,000    ($6,750,000)    ($3,760,000)       ($90,600)
NGLs--restore benchmarks:
    Remove affiliate Resale.....................        $754,000      ($529,000)      ($220,000)        ($4,830)
    Remove index................................    ($2,210,000)      $1,550,000        $646,000         $14,200
Gas transportation 50% limitation exceptions             $87,000       ($55,400)       ($30,900)          ($744)
 reinstated.....................................
Processing allowance 66\2/3\% limitation                 $42,700       ($29,900)       ($12,500)          ($274)
 exceptions reinstated..........................
POP contracts' processing allowance exceptions        $9,470,000    ($6,640,000)    ($2,770,000)       ($60,700)
 of 66\2/3\% limitation reinstated..............
Extraordinary processing allowance reinstated...     $14,200,000    ($7,100,000)    ($7,100,000)              $0
Deep-water-gathering reinstated.................     $28,100,000   ($28,100,000)              $0              $0
Oil transportation 50% limitation exceptions                  $0              $0              $0              $0
 reinstated.....................................
Oil and gas line losses allowance reinstated....      $3,140,000    ($2,560,000)      ($562,000)       ($17,200)
BBB bond rate change removed....................      $5,740,000    ($4,680,000)    ($1,030,000)       ($31,500)
Coal provisions.................................              $0              $0              $0              $0
                                                 ---------------------------------------------------------------
    Total.......................................     $71,300,000   ($55,800,000)   ($15,300,000)      ($200,000)
----------------------------------------------------------------------------------------------------------------
Note: totals from this table and others in this analysis may not add due to rounding.

B. Regulatory Planning and Review (Executive Orders 12866 and 13563 and 
Executive Order 13771 on Reducing Regulation and Controlling Regulatory 
Costs Dated January 30, 2017)

    Executive Order (E.O.) 12866 provides that the Office of 
Information and Regulatory Affairs (OIRA) of the Office of Management 
and Budget (OMB) will review all significant rules. OIRA has determined 
that this rule is significant because it may materially alter the 
budgetary impact of entitlements, grants, user fees, or loan programs 
or the rights and obligations of recipients thereof.
    Executive Order 13563 reaffirms the principles of E.O. 12866, while 
calling for improvements in the Nation's regulatory system to promote 
predictability, to reduce uncertainty, and to use the best, most 
innovative, and least burdensome tools for achieving regulatory ends. 
This Executive Order directs agencies to consider regulatory approaches 
that reduce burdens and maintain flexibility and freedom of choice for 
the public where these approaches are relevant, feasible, and 
consistent with regulatory objectives. E.O. 13563 emphasizes further 
that regulations must be based on the best available science and that 
the rulemaking process must allow for public participation and an open 
exchange of ideas. We developed this rule in a manner consistent with 
these requirements.
    This final rule is considered a deregulatory action under E.O. 
13771, Reducing Regulation and Controlling Regulatory Costs (82 FR 
9339, Feb. 3, 2017). Although there are some costs to industry 
associated with this rule, the

[[Page 36952]]

rule still results in an overall savings to industry. Details on the 
estimated savings and costs associated with the rule can be found in 
the rule's economic analysis.

C. Regulatory Flexibility Act

    The Department of the Interior (Department) certifies that this 
rule will not have a significant economic effect on a substantial 
number of small entities under the Regulatory Flexibility Act (5 U.S.C. 
601 et seq.). See the 2017 Valuation Rule, Procedural Matters, item 1, 
starting at 81 FR 43359, and item 3, starting at 81 FR 43367.
    This rule will affect only lessees under Federal oil and gas leases 
and Federal and Indian coal leases.
    The Department certifies that this rule will not have a significant 
economic effect on a substantial number of small entities under the 
Regulatory Flexibility Act (5 U.S.C. 601 et seq.), see item 1 above for 
the analysis.
    This rule will affect lessees under Federal oil and gas leases and 
Federal and Indian coal leases. Federal and Indian mineral lessees are, 
generally, companies classified under the North American Industry 
Classification System (NAICS), as follows:

 Code 211111, which includes companies that extract crude 
petroleum and natural gas
 Code 212111, which includes companies that extract surface 
coal
 Code 212112, which includes companies that extract underground 
coal

    For these NAICS code classifications, a small company is one with 
fewer than 500 employees. Approximately 1,920 different companies 
submit royalty and production reports from Federal oil and gas leases 
and Federal and Indian coal leases to us each month. Of these, 
approximately 65 companies are large businesses under the U.S. Small 
Business Administration definition because they have more than 500 
employees. The Department estimates that the remaining 1,855 companies 
that this rule affects are small businesses.
    As we stated earlier, based on 2015 sales data, this rule is a 
benefit to industry of approximately $71 million dollars per year. 
Small businesses accounted for about 20 percent of the royalties paid 
in 2015. Applying that percentage to industry costs, we estimate that 
this final rule will benefit all small-business lessors approximately 
$14,200,000 per year. The amount will vary for each company depending 
on the volume of production that each small business produces and sells 
each year.
    In sum, we do not estimate that this rule will result in a 
significant economic effect on a substantial number of small entities 
because this rule will benefit affected small businesses a collective 
total of $14,200,000 per year.

D. Small Business Regulatory Enforcement Fairness Act

    This rule is not a major rule under 5 U.S.C. 804(2), the Small 
Business Regulatory Enforcement Fairness Act. This rule:
    (1) Does not have an annual effect on the economy of $100 million 
or more. We estimate that industry will annually benefit between 
$60,100,000 and $74,800,000. These figures are a reversal of the 
impacts described in the 2017 Valuation Rule, under Procedural Matters, 
item 1, starting at 81 FR 43359, and item 4, 81 FR 43368, but has been 
adjusted to include more current data. Therefore, the economic impact 
on industry, State and local governments and the Federal government 
will be below the $100 million threshold that the Federal government 
uses to define a rule as having a significant impact on the economy.
    (2) Will not cause a major increase in costs or prices for 
consumers; individual industries; Federal, State, or local government 
agencies; or geographic regions. See Procedural Matters, item 1.
    (3) Does not have significant adverse effects on competition, 
employment, investment, productivity, innovation, or the ability of U 
S-based enterprises to compete with foreign-based enterprises. This 
rule will benefit U.S.-based enterprises.

E. Unfunded Mandates Reform Act

    This rule does not impose an unfunded mandate on State, local, or 
Tribal governments or the private sector of more than $100 million per 
year. This rule does not have a significant or unique effect on State, 
local, or Tribal governments or the private sector. Therefore, we are 
not required to provide a statement containing the information that the 
Unfunded Mandates Reform Act (2 U.S.C. 1501 et seq.) requires. See 
Procedural Matters, item 1.

F. Takings (E.O. 12630)

    Under the criteria in section 2 of E.O. 12630, this rule does not 
have any significant takings implications. This rule will not impose 
conditions or limitations on the use of any private property. This rule 
will apply to Federal oil, Federal gas, Federal coal, and Indian coal 
leases only. Therefore, this rule does not require a Takings 
Implication Assessment.

G. Federalism (E.O. 13132)

    Under the criteria in section 1 of E.O. 13132, this rule does not 
have sufficient Federalism implications to warrant the preparation of a 
Federalism assessment. The management of Federal oil and gas leases, 
and Federal and Indian coal leases is the responsibility of the 
Secretary of the Interior. This rule does not impose administrative 
costs on States or local governments. This rule also does not 
substantially and directly affect the relationship between the Federal 
and State governments. Because this rule does not alter that 
relationship, this rule does not require a Federalism summary impact 
statement.

H. Civil Justice Reform (E.O. 12988)

    This rule complies with the requirements of E.O. 12988. 
Specifically, this rule:
    (a) Meets the criteria of Sec.  3(a), which requires that we review 
all regulations to eliminate errors and ambiguity and write them to 
minimize litigation.
    (b) Meets the criteria of Sec.  3(b)(2), which requires that we 
write all regulations in clear language using clear legal standards.

I. Consultation With Indian Tribes (E.O. 13175 and Departmental Policy)

    The Department strives to strengthen its government-to-government 
relationship with Indian Tribes through a commitment to consultation 
with Indian Tribes and recognition of their right to self-governance 
and Tribal sovereignty. Under the criteria in E.O. 13175, we evaluated 
this final rule and determined that it will have no potential effects 
on Federally-recognized Indian Tribes. Specifically, we determined that 
this rule will restore the historical valuation methodology for coal 
produced from Indian leases. Accordingly:
    (1) We mailed letters, on April 3, 2017, to the Crow Tribe of 
Montana, Hopi Tribe of Arizona, and Navajo Nation to consult with the 
Tribes on both the Notice of Proposed Rulemaking and Advance Notice of 
Proposed Rulemaking for the proposed repeal of 2017 Indian coal 
valuation regulations.
    (2) We consulted with the Navajo Nation on May 24, 2017, in Window 
Rock, Arizona.
    (3) We consulted with the Crow Tribe on May 26, 2017, in Crow 
Agency, Montana.
    (4) We consulted with the Hopi on June 21, 2017, in Kykotsmovi, 
Arizona.

[[Page 36953]]

J. Paperwork Reduction Act

    This rule:
    (1) Does not contain any new information collection requirements.
    (2) Does not require a submission to the OMB under the Paperwork 
Reduction Act of 1995 (44 U.S.C. 3501 et seq.). See 5 CFR 1320.4(a)(2).
    This rule will leave intact the information collection requirements 
that OMB already approved under OMB Control Numbers 1012-0004, 1012-
0005, and 1012-0010.

K. National Environmental Policy Act

    This rule does not constitute a major Federal action significantly 
affecting the quality of the human environment. We are not required to 
provide a detailed statement under the National Environmental Policy 
Act of 1969 (NEPA) because this rule qualifies for a categorical 
exclusion under 43 CFR 46.210(i) in that this is ``. . . of an 
administrative, financial, legal, technical, or procedural nature. . . 
.'' This rule also qualifies for categorically exclusion under 
Departmental Manual, part 516, section 15.4.(C)(1) in that its impacts 
are limited to administrative, economic, or technological effects. We 
also have determined that this rule is not involved in any of the 
extraordinary circumstances listed in 43 CFR 46.215 that require 
further analysis under NEPA. The procedural changes resulting from the 
repeal of the 2017 Valuation Rule will have no consequence on the 
physical environment. This rule does not alter, in any material way, 
natural resources exploration, production, or transportation.

L. Effects on the Nation's Energy Supply (E.O. 13211)

    This rule is not a significant energy action under the definition 
in E.O. 13211; therefore, a Statement of Energy Effects is not 
required.

List of Subjects

30 CFR Part 1202

    Coal, Continental shelf, Government contracts, Indian lands, 
Mineral royalties, Natural gas, Oil and gas exploration, Public lands--
mineral resources, Reporting and recordkeeping requirements.

30 CFR Part 1206

    Coal, Continental shelf, Government contracts, Indian lands, 
Mineral royalties, Oil and gas exploration, Public lands--mineral 
resources, Reporting and recordkeeping requirements.

Gregory J. Gould,
Director for Office of Natural Resources Revenue.

Authority and Issuance

    For the reasons discussed in the preamble, ONRR amends 30 CFR parts 
1202 and 1206 as set forth below:

PART 1202--ROYALTIES

0
1. The authority citation for part 1202 continues to read as follows:

    Authority: 5 U.S.C. 301 et seq., 25 U.S.C. 396 et seq., 396a et 
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et 
seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq.,1331 et 
seq., and 1801 et seq.

Subpart B--Oil, Gas, and OCS Sulfur, General

0
2. In Sec.  1202.51, revise paragraph (b) to read as follows:


Sec.  1202.51  Scope and definitions.

* * * * *
    (b) The definitions in subparts B, C, D, and E of part 1206 of this 
title are applicable to subparts B, C, D, and J of this part.

Subpart F--Coal

0
3. Remove Sec.  1202.251.

PART 1206--PRODUCT VALUATION

0
4. The authority citation for part 1206 continues to read as follows:

    Authority:  5 U.S.C. 301 et seq., 25 U.S.C. 396 et seq., 396a et 
seq., 2101 et seq.; 30 U.S.C. 181 et seq., 351 et seq., 1001 et 
seq., 1701 et seq.; 31 U.S.C. 9701; 43 U.S.C. 1301 et seq., 1331 et 
seq., and 1801 et seq.

0
5. Revise subpart A, consisting of Sec.  1206.10, to read as follows:

Subpart A--General Provisions and Definitions


Sec.  [thinsp]1206.10  Information collection.

    The information collection requirements contained in this part have 
been approved by the Office of Management and Budget (OMB) under 44 
U.S.C. 3501 et seq. The forms, filing date, and approved OMB clearance 
numbers are identified in Sec.  [thinsp]1210.10.

0
6. Revise subpart C to read as follows:
Subpart C--Federal Oil
Sec.
1206.100 What is the purpose of this subpart?
1206.101 What definitions apply to this subpart?
1206.102 How do I calculate royalty value for oil that I or my 
affiliate sell(s) under an arm's-length contract?
1206.103 How do I value oil that is not sold under an arm's-length 
contract?
1206.104 What publications are acceptable to ONRR?
1206.105 What records must I keep to support my calculations of 
value under this subpart?
1206.106 What are my responsibilities to place production into 
marketable condition and to market production?
1206.107 How do I request a value determination?
1206.108 Does ONRR protect information I provide?
1206.109 When may I take a transportation allowance in determining 
value?
1206.110 How do I determine a transportation allowance under an 
arm's-length transportation contract?
1206.111 How do I determine a transportation allowance if I do not 
have an arm's-length transportation contract or arm's-length tariff?
1206.112 What adjustments and transportation allowances apply when I 
value oil production from my lease using NYMEX prices or ANS spot 
prices?
1206.113 How will ONRR identify market centers?
1206.114 What are my reporting requirements under an arm's-length 
transportation contract?
1206.115 What are my reporting requirements under a non-arm's-length 
transportation arrangement?
1206.116 What interest applies if I improperly report a 
transportation allowance?
1206.117 What reporting adjustments must I make for transportation 
allowances?
1206.119 How are the royalty quantity and quality determined?
1206.120 How are operating allowances determined?

Subpart C--Federal Oil


Sec.  [thinsp]1206.100  What is the purpose of this subpart?

    (a) This subpart applies to all oil produced from Federal oil and 
gas leases onshore and on the Outer Continental Shelf (OCS). It 
explains how you as a lessee must calculate the value of production for 
royalty purposes consistent with the mineral leasing laws, other 
applicable laws, and lease terms.
    (b) If you are a designee and if you dispose of production on 
behalf of a lessee, the terms ``you'' and ``your'' in this subpart 
refer to you and not to the lessee. In this circumstance, you must 
determine and report royalty value for the lessee's oil by applying the 
rules in this subpart to your disposition of the lessee's oil.
    (c) If you are a designee and only report for a lessee, and do not 
dispose of the lessee's production, references to ``you'' and ``your'' 
in this subpart refer to the lessee and not the designee. In this 
circumstance, you as a designee

[[Page 36954]]

must determine and report royalty value for the lessee's oil by 
applying the rules in this subpart to the lessee's disposition of its 
oil.
    (d) If the regulations in this subpart are inconsistent with:
    (1) A Federal statute;
    (2) A settlement agreement between the United States and a lessee 
resulting from administrative or judicial litigation;
    (3) A written agreement between the lessee and the ONRR Director 
establishing a method to determine the value of production from any 
lease that ONRR expects at least would approximate the value 
established under this subpart; or
    (4) An express provision of an oil and gas lease subject to this 
subpart, then the statute, settlement agreement, written agreement, or 
lease provision will govern to the extent of the inconsistency.
    (e) ONRR may audit and adjust all royalty payments.


Sec.  [thinsp]1206.101  What definitions apply to this subpart?

    The following definitions apply to this subpart:
    Affiliate means a person who controls, is controlled by, or is 
under common control with another person. For purposes of this subpart:
    (1) Ownership or common ownership of more than 50 percent of the 
voting securities, or instruments of ownership, or other forms of 
ownership, of another person constitutes control. Ownership of less 
than 10 percent constitutes a presumption of noncontrol that ONRR may 
rebut.
    (2) If there is ownership or common ownership of 10 through 50 
percent of the voting securities or instruments of ownership, or other 
forms of ownership, of another person, ONRR will consider the following 
factors in determining whether there is control under the circumstances 
of a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership: the percentage of ownership or 
common ownership, the relative percentage of ownership or common 
ownership compared to the percentage(s) of ownership by other persons, 
whether a person is the greatest single owner, or whether there is an 
opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, or other facility; and
    (v) Other evidence of power to exercise control over or common 
control with another person.
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    ANS means Alaska North Slope (ANS).
    Area means a geographic region at least as large as the limits of 
an oil field, in which oil has similar quality, economic, and legal 
characteristics.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this 
definition for that month, as well as when the contract was executed.
    Audit means a review, conducted under generally accepted accounting 
and auditing standards, of royalty payment compliance activities of 
lessees, designees or other persons who pay royalties, rents, or 
bonuses on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    BOEM means the Bureau of Ocean Energy Management of the Department 
of the Interior.
    BSEE means the Bureau of Safety and Environmental Enforcement of 
the Department of the Interior.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without processing. Condensate 
is the mixture of liquid hydrocarbons resulting from condensation of 
petroleum hydrocarbons existing initially in a gaseous phase in an 
underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions, between two or more persons, that is enforceable by law 
and that with due consideration creates an obligation.
    Designee means the person the lessee designates to report and pay 
the lessee's royalties for a lease.
    Exchange agreement means an agreement where one person agrees to 
deliver oil to another person at a specified location in exchange for 
oil deliveries at another location. Exchange agreements may or may not 
specify prices for the oil involved. They frequently specify dollar 
amounts reflecting location, quality, or other differentials. Exchange 
agreements include buy/sell agreements, which specify prices to be paid 
at each exchange point and may appear to be two separate sales within 
the same agreement. Examples of other types of exchange agreements 
include, but are not limited to, exchanges of produced oil for specific 
types of crude oil (e.g., West Texas Intermediate); exchanges of 
produced oil for other crude oil at other locations (Location Trades); 
exchanges of produced oil for other grades of oil (Grade Trades); and 
multi-party exchanges.
    Field means a geographic region situated over one or more 
subsurface oil and gas reservoirs and encompassing at least the 
outermost boundaries of all oil and gas accumulations known within 
those reservoirs, vertically projected to the land surface. State oil 
and gas regulatory agencies usually name onshore fields and designate 
their official boundaries. BOEM names and designates boundaries of OCS 
fields.
    Gathering means the movement of lease production to a central 
accumulation or treatment point on the lease, unit, or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit, or communitized area that BLM or BSEE approves for onshore and 
offshore leases, respectively.
    Gross proceeds means the total monies and other consideration 
accruing for the disposition of oil produced. Gross proceeds also 
include, but are not limited to, the following examples:
    (1) Payments for services such as dehydration, marketing, 
measurement, or gathering which the lessee must perform at no cost to 
the Federal Government;
    (2) The value of services, such as salt water disposal, that the 
producer normally performs but that the buyer performs on the 
producer's behalf;
    (3) Reimbursements for harboring or terminaling fees;
    (4) Tax reimbursements, even though the Federal royalty interest 
may be exempt from taxation;
    (5) Payments made to reduce or buy down the purchase price of oil 
to be produced in later periods, by allocating such payments over the 
production whose price the payment reduces and including the allocated 
amounts as proceeds for the production as it occurs; and
    (6) Monies and all other consideration to which a seller is 
contractually or legally entitled, but does not seek to collect through 
reasonable efforts.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under a 
mineral leasing law that authorizes exploration for, development or 
extraction of, or

[[Page 36955]]

removal of oil or gas--or the land area covered by that authorization, 
whichever the context requires.
    Lessee means any person to whom the United States issues an oil and 
gas lease, an assignee of all or a part of the record title interest, 
or any person to whom operating rights in a lease have been assigned.
    Location differential means an amount paid or received (whether in 
money or in barrels of oil) under an exchange agreement that results 
from differences in location between oil delivered in exchange and oil 
received in the exchange. A location differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell exchange agreement.
    Market center means a major point ONRR recognizes for oil sales, 
refining, or transshipment. Market centers generally are locations 
where ONRR-approved publications publish oil spot prices.
    Marketable condition means oil sufficiently free from impurities 
and otherwise in a condition a purchaser will accept under a sales 
contract typical for the field or area.
    Netting means reducing the reported sales value to account for 
transportation instead of reporting a transportation allowance as a 
separate entry on form ONRR-2014.
    NYMEX price means the average of the New York Mercantile Exchange 
(NYMEX) settlement prices for light sweet crude oil delivered at 
Cushing, Oklahoma, calculated as follows:
    (1) Sum the prices published for each day during the calendar month 
of production (excluding weekends and holidays) for oil to be delivered 
in the prompt month corresponding to each such day; and
    (2) Divide the sum by the number of days on which those prices are 
published (excluding weekends and holidays).
    Oil means a mixture of hydrocarbons that existed in the liquid 
phase in natural underground reservoirs, remains liquid at atmospheric 
pressure after passing through surface separating facilities, and is 
marketed or used as a liquid. Condensate recovered in lease separators 
or field facilities is oil.
    ONRR-approved publication means a publication ONRR approves for 
determining ANS spot prices or WTI differentials.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of lands beneath navigable waters as 
defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Prompt month means the nearest month of delivery for which NYMEX 
futures prices are published during the trading month.
    Quality differential means an amount paid or received under an 
exchange agreement (whether in money or in barrels of oil) that results 
from differences in API gravity, sulfur content, viscosity, metals 
content, and other quality factors between oil delivered and oil 
received in the exchange. A quality differential may represent all or 
part of the difference between the price received for oil delivered and 
the price paid for oil received under a buy/sell agreement.
    Rocky Mountain Region means the States of Colorado, Montana, North 
Dakota, South Dakota, Utah, and Wyoming, except for those portions of 
the San Juan Basin and other oil-producing fields in the ``Four 
Corners'' area that lie within Colorado and Utah.
    Roll means an adjustment to the NYMEX price that is calculated as 
follows: Roll = .6667 x (P0 - P1) + .3333 x 
(P0 - P2), where: P0 = the average of 
the daily NYMEX settlement prices for deliveries during the prompt 
month that is the same as the month of production, as published for 
each day during the trading month for which the month of production is 
the prompt month; P1 = the average of the daily NYMEX 
settlement prices for deliveries during the month following the month 
of production, published for each day during the trading month for 
which the month of production is the prompt month; and P2 = 
the average of the daily NYMEX settlement prices for deliveries during 
the second month following the month of production, as published for 
each day during the trading month for which the month of production is 
the prompt month. Calculate the average of the daily NYMEX settlement 
prices using only the days on which such prices are published 
(excluding weekends and holidays).
    (1) Example 1. Prices in Out Months are Lower Going Forward: The 
month of production for which you must determine royalty value is 
March. March was the prompt month (for year 2003) from January 22 
through February 20. April was the first month following the month of 
production, and May was the second month following the month of 
production. P0 therefore is the average of the daily NYMEX 
settlement prices for deliveries during March published for each 
business day between January 22 and February 20. P1 is the 
average of the daily NYMEX settlement prices for deliveries during 
April published for each business day between January 22 and February 
20. P2 is the average of the daily NYMEX settlement prices 
for deliveries during May published for each business day between 
January 22 and February 20. In this example, assume that P0 
= $28.00 per bbl, P1 = $27.70 per bbl, and P2 = 
$27.10 per bbl. In this example (a declining market), Roll = .6667 x 
($28.00 - $27.70) + .3333 x ($28.00 - $27.10) = $.20 + $.30 = $.50. You 
add this number to the NYMEX price.
    (2) Example 2. Prices in Out Months are Higher Going Forward: The 
month of production for which you must determine royalty value is July. 
July 2003 was the prompt month from May 21 through June 20. August was 
the first month following the month of production, and September was 
the second month following the month of production. P0 
therefore is the average of the daily NYMEX settlement prices for 
deliveries during July published for each business day between May 21 
and June 20. P1 is the average of the daily NYMEX settlement 
prices for deliveries during August published for each business day 
between May 21 and June 20. P2 is the average of the daily 
NYMEX settlement prices for deliveries during September published for 
each business day between May 21 and June 20. In this example, assume 
that P0 = $28.00 per bbl, P1 = $28.90 per bbl, 
and P2 = $29.50 per bbl. In this example (a rising market), 
Roll = .6667 x ($28.00-$28.90) + .3333 x ($28.00 - $29.50) = (-$.60) + 
(-$.50) = -$1.10. You add this negative number to the NYMEX price 
(effectively a subtraction from the NYMEX price).
    Sale means a contract between two persons where:
    (1) The seller unconditionally transfers title to the oil to the 
buyer and does not retain any related rights such as the right to buy 
back similar quantities of oil from the buyer elsewhere;
    (2) The buyer pays money or other consideration for the oil; and
    (3) The parties' intent is for a sale of the oil to occur.
    Spot price means the price under a spot sales contract where:
    (1) A seller agrees to sell to a buyer a specified amount of oil at 
a specified price over a specified period of short duration;
    (2) No cancellation notice is required to terminate the sales 
agreement; and

[[Page 36956]]

    (3) There is no obligation or implied intent to continue to sell in 
subsequent periods.
    Tendering program means a producer's offer of a portion of its 
crude oil produced from a field or area for competitive bidding, 
regardless of whether the production is offered or sold at or near the 
lease or unit or away from the lease or unit.
    Trading month means the period extending from the second business 
day before the 25th day of the second calendar month preceding the 
delivery month (or, if the 25th day of that month is a non-business 
day, the second business day before the last business day preceding the 
25th day of that month) through the third business day before the 25th 
day of the calendar month preceding the delivery month (or, if the 25th 
day of that month is a non-business day, the third business day before 
the last business day preceding the 25th day of that month), unless the 
NYMEX publishes a different definition or different dates on its 
official Web site, www.nymex.com, in which case the NYMEX definition 
will apply.
    Transportation allowance means a deduction in determining royalty 
value for the reasonable, actual costs of moving oil to a point of sale 
or delivery off the lease, unit area, or communitized area. The 
transportation allowance does not include gathering costs.
    WTI differential means the average of the daily mean differentials 
for location and quality between a grade of crude oil at a market 
center and West Texas Intermediate (WTI) crude oil at Cushing published 
for each day for which price publications perform surveys for 
deliveries during the production month, calculated over the number of 
days on which those differentials are published (excluding weekends and 
holidays). Calculate the daily mean differentials by averaging the 
daily high and low differentials for the month in the selected 
publication. Use only the days and corresponding differentials for 
which such differentials are published.
    (1) Example. Assume the production month was March 2003. Industry 
trade publications performed their price surveys and determined 
differentials during January 26 through February 25 for oil delivered 
in March. The WTI differential (for example, the West Texas Sour crude 
at Midland, Texas, spread versus WTI) applicable to valuing oil 
produced in the March 2003 production month would be determined using 
all the business days for which differentials were published during the 
period January 26 through February 25 excluding weekends and holidays 
(22 days). To calculate the WTI differential, add together all of the 
daily mean differentials published for January 26 through February 25 
and divide that sum by 22.
    (2) [Reserved]


Sec.  [thinsp]1206.102  How do I calculate royalty value for oil that I 
or my affiliate sell(s) under an arm's-length contract?

    (a) The value of oil under this section is the gross proceeds 
accruing to the seller under the arm's-length contract, less applicable 
allowances determined under Sec.  [thinsp]1206.110 or Sec.  
[thinsp]1206.111. This value does not apply if you exercise an option 
to use a different value provided in paragraph (d)(1) or (d)(2)(i) of 
this section, or if one of the exceptions in paragraph (c) of this 
section applies. Use this paragraph (a) to value oil that:
    (1) You sell under an arm's-length sales contract; or
    (2) You sell or transfer to your affiliate or another person under 
a non-arm's-length contract and that affiliate or person, or another 
affiliate of either of them, then sells the oil under an arm's-length 
contract, unless you exercise the option provided in paragraph 
(d)(2)(i) of this section.
    (b) If you have multiple arm's-length contracts to sell oil 
produced from a lease that is valued under paragraph (a) of this 
section, the value of the oil is the volume-weighted average of the 
values established under this section for each contract for the sale of 
oil produced from that lease.
    (c) This paragraph contains exceptions to the valuation rule in 
paragraph (a) of this section. Apply these exceptions on an individual 
contract basis.
    (1) In conducting reviews and audits, if ONRR determines that any 
arm's-length sales contract does not reflect the total consideration 
actually transferred either directly or indirectly from the buyer to 
the seller, ONRR may require that you value the oil sold under that 
contract either under Sec.  [thinsp]1206.103 or at the total 
consideration received.
    (2) You must value the oil under Sec.  [thinsp]1206.103 if ONRR 
determines that the value under paragraph (a) of this section does not 
reflect the reasonable value of the production due to either:
    (i) Misconduct by or between the parties to the arm's-length 
contract; or
    (ii) Breach of your duty to market the oil for the mutual benefit 
of yourself and the lessor.
    (A) ONRR will not use this provision to simply substitute its 
judgment of the market value of the oil for the proceeds received by 
the seller under an arm's-length sales contract.
    (B) The fact that the price received by the seller under an arm's-
length contract is less than other measures of market price, such as 
index prices, is insufficient to establish breach of the duty to market 
unless ONRR finds additional evidence that the seller acted 
unreasonably or in bad faith in the sale of oil from the lease.
    (d)(1) If you enter into an arm's-length exchange agreement, or 
multiple sequential arm's-length exchange agreements, and following the 
exchange(s) you or your affiliate sell(s) the oil received in the 
exchange(s) under an arm's-length contract, then you may use either 
Sec.  [thinsp]1206.102(a) or Sec.  [thinsp]1206.103 to value your 
production for royalty purposes.
    (i) If you use Sec.  [thinsp]1206.102(a), your gross proceeds are 
the gross proceeds under your or your affiliate's arm's-length sales 
contract after the exchange(s) occur(s). You must adjust your gross 
proceeds for any location or quality differential, or other 
adjustments, you received or paid under the arm's-length exchange 
agreement(s). If ONRR determines that any arm's-length exchange 
agreement does not reflect reasonable location or quality 
differentials, ONRR may require you to value the oil under Sec.  
[thinsp]1206.103. You may not otherwise use the price or differential 
specified in an arm's-length exchange agreement to value your 
production.
    (ii) When you elect under Sec.  [thinsp]1206.102(d)(1) to use Sec.  
[thinsp]1206.102(a) or Sec.  [thinsp]1206.103, you must make the same 
election for all of your production from the same unit, communitization 
agreement, or lease (if the lease is not part of a unit or 
communitization agreement) sold under arm's-length contracts following 
arm's-length exchange agreements. You may not change your election more 
often than once every 2 years.
    (2)(i) If you sell or transfer your oil production to your 
affiliate and that affiliate or another affiliate then sells the oil 
under an arm's-length contract, you may use either Sec.  
[thinsp]1206.102(a) or Sec.  [thinsp]1206.103 to value your production 
for royalty purposes.
    (ii) When you elect under Sec.  [thinsp]1206.102(d)(2)(i) to use 
Sec.  [thinsp]1206.102(a) or Sec.  [thinsp]1206.103, you must make the 
same election for all of your production from the same unit, 
communitization agreement, or lease (if the lease is not part of a unit 
or communitization agreement) that your affiliates resell at arm's 
length. You may not change your election more often than once every 2 
years.
    (e) If you value oil under paragraph (a) of this section:
    (1) ONRR may require you to certify that your or your affiliate's 
arm's-length

[[Page 36957]]

contract provisions include all of the consideration the buyer must 
pay, either directly or indirectly, for the oil.
    (2) You must base value on the highest price the seller can receive 
through legally enforceable claims under the contract.
    (i) If the seller fails to take proper or timely action to receive 
prices or benefits it is entitled to, you must pay royalty at a value 
based upon that obtainable price or benefit. But you will owe no 
additional royalties unless or until the seller receives monies or 
consideration resulting from the price increase or additional benefits, 
if:
    (A) The seller makes timely application for a price increase or 
benefit allowed under the contract;
    (B) The purchaser refuses to comply; and
    (C) The seller takes reasonable documented measures to force 
purchaser compliance.
    (ii) Paragraph (e)(2)(i) of this section will not permit you to 
avoid your royalty payment obligation where a purchaser fails to pay, 
pays only in part, or pays late. Any contract revisions or amendments 
that reduce prices or benefits to which the seller is entitled must be 
in writing and signed by all parties to the arm's-length contract.


Sec.  [thinsp]1206.103  How do I value oil that is not sold under an 
arm's-length contract?

    This section explains how to value oil that you may not value under 
Sec.  [thinsp]1206.102 or that you elect under Sec.  
[thinsp]1206.102(d) to value under this section. First determine 
whether paragraph (a), (b), or (c) of this section applies to 
production from your lease, or whether you may apply paragraph (d) or 
(e) with ONRR approval.
    (a) Production from leases in California or Alaska. Value is the 
average of the daily mean ANS spot prices published in any ONRR-
approved publication during the trading month most concurrent with the 
production month. (For example, if the production month is June, 
compute the average of the daily mean prices using the daily ANS spot 
prices published in the ONRR-approved publication for all the business 
days in June.)
    (1) To calculate the daily mean spot price, average the daily high 
and low prices for the month in the selected publication.
    (2) Use only the days and corresponding spot prices for which such 
prices are published.
    (3) You must adjust the value for applicable location and quality 
differentials, and you may adjust it for transportation costs, under 
Sec.  [thinsp]1206.112.
    (4) After you select an ONRR-approved publication, you may not 
select a different publication more often than once every 2 years, 
unless the publication you use is no longer published or ONRR revokes 
its approval of the publication. If you are required to change 
publications, you must begin a new 2-year period.
    (b) Production from leases in the Rocky Mountain Region. This 
paragraph provides methods and options for valuing your production 
under different factual situations. You must consistently apply 
paragraph (b)(1), (2), or (3) of this section to value all of your 
production from the same unit, communitization agreement, or lease (if 
the lease or a portion of the lease is not part of a unit or 
communitization agreement) that you cannot value under Sec.  
[thinsp]1206.102 or that you elect under Sec.  [thinsp]1206.102(d) to 
value under this section.
    (1) If you have an ONRR-approved tendering program, you must value 
oil produced from leases in the area the tendering program covers at 
the highest winning bid price for tendered volumes.
    (i) The minimum requirements for ONRR to approve your tendering 
program are:
    (A) You must offer and sell at least 30 percent of your or your 
affiliates' production from both Federal and non-Federal leases in the 
area under your tendering program; and
    (B) You must receive at least three bids for the tendered volumes 
from bidders who do not have their own tendering programs that cover 
some or all of the same area.
    (ii) If you do not have an ONRR-approved tendering program, you may 
elect to value your oil under either paragraph (b)(2) or (3) of this 
section. After you select either paragraph (b)(2) or (3) of this 
section, you may not change to the other method more often than once 
every 2 years, unless the method you have been using is no longer 
applicable and you must apply the other paragraph. If you change 
methods, you must begin a new 2-year period.
    (2) Value is the volume-weighted average of the gross proceeds 
accruing to the seller under your or your affiliates' arm's-length 
contracts for the purchase or sale of production from the field or area 
during the production month.
    (i) The total volume purchased or sold under those contracts must 
exceed 50 percent of your and your affiliates' production from both 
Federal and non-Federal leases in the same field or area during that 
month.
    (ii) Before calculating the volume-weighted average, you must 
normalize the quality of the oil in your or your affiliates' arm's-
length purchases or sales to the same gravity as that of the oil 
produced from the lease.
    (3) Value is the NYMEX price (without the roll), adjusted for 
applicable location and quality differentials and transportation costs 
under Sec.  [thinsp]1206.112.
    (4) If you demonstrate to ONRR's satisfaction that paragraphs 
(b)(1) through (b)(3) of this section result in an unreasonable value 
for your production as a result of circumstances regarding that 
production, the ONRR Director may establish an alternative valuation 
method.
    (c) Production from leases not located in California, Alaska, or 
the Rocky Mountain Region. (1) Value is the NYMEX price, plus the roll, 
adjusted for applicable location and quality differentials and 
transportation costs under Sec.  [thinsp]1206.112.
    (2) If the ONRR Director determines that use of the roll no longer 
reflects prevailing industry practice in crude oil sales contracts or 
that) the most common formula used by industry to calculate the roll 
changes, ONRR may terminate or modify use of the roll under paragraph 
(c)(1) of this section at the end of each 2-year period following July 
6, 2004, through notice published in the Federal Register not later 
than 60 days before the end of the 2-year period. ONRR will explain the 
rationale for terminating or modifying the use of the roll in this 
notice.
    (d) Unreasonable value. If ONRR determines that the NYMEX price or 
ANS spot price does not represent a reasonable royalty value in any 
particular case, ONRR may establish reasonable royalty value based on 
other relevant matters.
    (e) Production delivered to your refinery and the NYMEX price or 
ANS spot price is an unreasonable value. (1) Instead of valuing your 
production under paragraph (a), (b), or (c) of this section, you may 
apply to the ONRR Director to establish a value representing the market 
at the refinery if:
    (i) You transport your oil directly to your or your affiliate's 
refinery, or exchange your oil for oil delivered to your or your 
affiliate's refinery; and
    (ii) You must value your oil under this section at the NYMEX price 
or ANS spot price; and
    (iii) You believe that use of the NYMEX price or ANS spot price 
results in an unreasonable royalty value.
    (2) You must provide adequate documentation and evidence 
demonstrating the market value at the refinery. That evidence may 
include, but is not limited to:

[[Page 36958]]

    (i) Costs of acquiring other crude oil at or for the refinery;
    (ii) How adjustments for quality, location, and transportation were 
factored into the price paid for other oil;
    (iii) Volumes acquired for and refined at the refinery; and
    (iv) Any other appropriate evidence or documentation that ONRR 
requires.
    (3) If the ONRR Director establishes a value representing market 
value at the refinery, you may not take an allowance against that value 
under Sec.  [thinsp]1206.112(b) unless it is included in the Director's 
approval.


Sec.  [thinsp]1206.104  What publications are acceptable to ONRR?

    (a) ONRR periodically will publish in the Federal Register a list 
of acceptable publications for the NYMEX price and ANS spot price based 
on certain criteria, including, but not limited to:
    (1) Publications buyers and sellers frequently use;
    (2) Publications frequently mentioned in purchase or sales 
contracts;
    (3) Publications that use adequate survey techniques, including 
development of estimates based on daily surveys of buyers and sellers 
of crude oil, and, for ANS spot prices, buyers and sellers of ANS crude 
oil; and
    (4) Publications independent from ONRR, other lessors, and lessees.
    (b) Any publication may petition ONRR to be added to the list of 
acceptable publications.
    (c) ONRR will specify the tables you must use in the acceptable 
publications.
    (d) ONRR may revoke its approval of a particular publication if it 
determines that the prices or differentials published in the 
publication do not accurately represent NYMEX prices or differentials 
or ANS spot market prices or differentials.


Sec.  [thinsp]1206.105  What records must I keep to support my 
calculations of value under this subpart?

    If you determine the value of your oil under this subpart, you must 
retain all data relevant to the determination of royalty value.
    (a) You must be able to show:
    (1) How you calculated the value you reported, including all 
adjustments for location, quality, and transportation, and
    (2) How you complied with these rules.
    (b) Recordkeeping requirements are found at part 1207 of this 
chapter.
    (c) ONRR may review and audit your data, and ONRR will direct you 
to use a different value if it determines that the reported value is 
inconsistent with the requirements of this subpart.


Sec.  [thinsp]1206.106  What are my responsibilities to place 
production into marketable condition and to market production?

    You must place oil in marketable condition and market the oil for 
the mutual benefit of the lessee and the lessor at no cost to the 
Federal Government. If you use gross proceeds under an arm's-length 
contract in determining value, you must increase those gross proceeds 
to the extent that the purchaser, or any other person, provides certain 
services that the seller normally would be responsible to perform to 
place the oil in marketable condition or to market the oil.


Sec.  [thinsp]1206.107  How do I request a value determination?

    (a) You may request a value determination from ONRR regarding any 
Federal lease oil production. Your request must:
    (1) Be in writing;
    (2) Identify specifically all leases involved, the record title or 
operating rights owners of those leases, and the designees for those 
leases;
    (3) Completely explain all relevant facts. You must inform ONRR of 
any changes to relevant facts that occur before we respond to your 
request;
    (4) Include copies of all relevant documents;
    (5) Provide your analysis of the issue(s), including citations to 
all relevant precedents (including adverse precedents); and
    (6) Suggest your proposed valuation method.
    (b) ONRR will reply to requests expeditiously. ONRR may either:
    (1) Issue a value determination signed by the Assistant Secretary, 
Policy, Management and Budget; or
    (2) Issue a value determination by ONRR; or
    (3) Inform you in writing that ONRR will not provide a value 
determination. Situations in which ONRR typically will not provide any 
value determination include, but are not limited to:
    (i) Requests for guidance on hypothetical situations; and
    (ii) Matters that are the subject of pending litigation or 
administrative appeals.
    (c)(1) A value determination signed by the Assistant Secretary, 
Policy, Management and Budget, is binding on both you and ONRR until 
the Assistant Secretary modifies or rescinds it.
    (2) After the Assistant Secretary issues a value determination, you 
must make any adjustments in royalty payments that follow from the 
determination and, if you owe additional royalties, pay late payment 
interest under Sec.  1218.54 of this chapter.
    (3) A value determination signed by the Assistant Secretary is the 
final action of the Department and is subject to judicial review under 
5 U.S.C. 701-706.
    (d) A value determination issued by ONRR is binding on ONRR and 
delegated States with respect to the specific situation addressed in 
the determination unless the ONRR (for ONRR-issued value 
determinations) or the Assistant Secretary modifies or rescinds it.
    (1) A value determination by ONRR is not an appealable decision or 
order under 30 CFR part 1290.
    (2) If you receive an order requiring you to pay royalty on the 
same basis as the value determination, you may appeal that order under 
30 CFR part 1290.
    (e) In making a value determination, ONRR or the Assistant 
Secretary may use any of the applicable valuation criteria in this 
subpart.
    (f) A change in an applicable statute or regulation on which any 
value determination is based takes precedence over the value 
determination, regardless of whether the ONRR or the Assistant 
Secretary modifies or rescinds the value determination.
    (g) The ONRR or the Assistant Secretary generally will not 
retroactively modify or rescind a value determination issued under 
paragraph (d) of this section, unless:
    (1) There was a misstatement or omission of material facts; or
    (2) The facts subsequently developed are materially different from 
the facts on which the guidance was based.
    (h) ONRR may make requests and replies under this section available 
to the public, subject to the confidentiality requirements under Sec.  
1206.108.


Sec.  1206.108  Does ONRR protect information I provide?

    Certain information you submit to ONRR regarding valuation of oil, 
including transportation allowances, may be exempt from disclosure. To 
the extent applicable laws and regulations permit, ONRR will keep 
confidential any data you submit that is privileged, confidential, or 
otherwise exempt from disclosure. All requests for information must be 
submitted under the Freedom of Information Act regulations of the 
Department of the Interior at 43 CFR part 2.


Sec.  1206.109  When may I take a transportation allowance in 
determining value?

    (a) Transportation allowances permitted when value is based on 
gross proceeds. ONRR will allow a deduction

[[Page 36959]]

for the reasonable, actual costs to transport oil from the lease to the 
point off the lease under Sec.  1206.110 or Sec.  1206.111, as 
applicable. This paragraph applies when:
    (1) You value oil under Sec.  1206.102 based on gross proceeds from 
a sale at a point off the lease, unit, or communitized area where the 
oil is produced, and
    (2) The movement to the sales point is not gathering.
    (b) Transportation allowances and other adjustments that apply when 
value is based on NYMEX prices or ANS spot prices. If you value oil 
using NYMEX prices or ANS spot prices under Sec.  1206.103, ONRR will 
allow an adjustment for certain location and quality differentials and 
certain costs associated with transporting oil as provided under Sec.  
1206.112.
    (c) Limits on transportation allowances. (1) Except as provided in 
paragraph (c)(2) of this section, your transportation allowance may not 
exceed 50 percent of the value of the oil as determined under Sec.  
1206.102 or Sec.  1206.103 of this subpart. You may not use 
transportation costs incurred to move a particular volume of production 
to reduce royalties owed on production for which those costs were not 
incurred.
    (2) You may ask ONRR to approve a transportation allowance in 
excess of the limitation in paragraph (c)(1) of this section. You must 
demonstrate that the transportation costs incurred were reasonable, 
actual, and necessary. Your application for exception (using form ONRR-
4393, Request to Exceed Regulatory Allowance Limitation) must contain 
all relevant and supporting documentation necessary for ONRR to make a 
determination. You may never reduce the royalty value of any production 
to zero.
    (d) Allocation of transportation costs. You must allocate 
transportation costs among all products produced and transported as 
provided in Sec. Sec.  1206.110 and 1206.111. You must express 
transportation allowances for oil as dollars per barrel.
    (e) Liability for additional payments. If ONRR determines that you 
took an excessive transportation allowance, then you must pay any 
additional royalties due, plus interest under Sec.  1218.54 of this 
chapter. You also could be entitled to a credit with interest under 
applicable rules if you understated your transportation allowance. If 
you take a deduction for transportation on form ONRR-2014 by improperly 
netting the allowance against the sales value of the oil instead of 
reporting the allowance as a separate entry, ONRR may assess you an 
amount under Sec.  1206.116.


Sec.  1206.110  How do I determine a transportation allowance under an 
arm's-length transportation contract?

    (a) If you or your affiliate incur transportation costs under an 
arm's-length transportation contract, you may claim a transportation 
allowance for the reasonable, actual costs incurred as more fully 
explained in paragraph (b) of this section, except as provided in 
paragraphs (a)(1) and (2) of this section and subject to the limitation 
in Sec.  1206.109(c). You must be able to demonstrate that your or your 
affiliate's contract is at arm's length. You do not need ONRR approval 
before reporting a transportation allowance for costs incurred under an 
arm's-length transportation contract.
    (1) If ONRR determines that the contract reflects more than the 
consideration actually transferred either directly or indirectly from 
you or your affiliate to the transporter for the transportation, ONRR 
may require that you calculate the transportation allowance under Sec.  
1206.111.
    (2) You must calculate the transportation allowance under Sec.  
1206.111 if ONRR determines that the consideration paid under an arm's-
length transportation contract does not reflect the reasonable value of 
the transportation due to either:
    (i) Misconduct by or between the parties to the arm's-length 
contract; or
    (ii) Breach of your duty to market the oil for the mutual benefit 
of yourself and the lessor.
    (A) ONRR will not use this provision to simply substitute its 
judgment of the reasonable oil transportation costs incurred by you or 
your affiliate under an arm's-length transportation contract.
    (B) The fact that the cost you or your affiliate incur in an arm's-
length transaction is higher than other measures of transportation 
costs, such as rates paid by others in the field or area, is 
insufficient to establish breach of the duty to market unless ONRR 
finds additional evidence that you or your affiliate acted unreasonably 
or in bad faith in transporting oil from the lease.
    (b) You may deduct any of the following actual costs you (including 
your affiliates) incur for transporting oil. You may not use as a 
deduction any cost that duplicates all or part of any other cost that 
you use under this paragraph.
    (1) The amount that you pay under your arm's-length transportation 
contract or tariff.
    (2) Fees paid (either in volume or in value) for actual or 
theoretical line losses.
    (3) Fees paid for administration of a quality bank.
    (4) The cost of carrying on your books as inventory a volume of oil 
that the pipeline operator requires you to maintain, and that you do 
maintain, in the line as line fill. You must calculate this cost as 
follows:
    (i) Multiply the volume that the pipeline requires you to maintain, 
and that you do maintain, in the pipeline by the value of that volume 
for the current month calculated under Sec.  1206.102 or Sec.  
1206.103, as applicable; and
    (ii) Multiply the value calculated under paragraph (b)(4)(i) of 
this section by the monthly rate of return, calculated by dividing the 
rate of return specified in Sec.  1206.111(i)(2) by 12.
    (5) Fees paid to a terminal operator for loading and unloading of 
crude oil into or from a vessel, vehicle, pipeline, or other 
conveyance.
    (6) Fees paid for short-term storage (30 days or less) incidental 
to transportation as required by a transporter.
    (7) Fees paid to pump oil to another carrier's system or vehicles 
as required under a tariff.
    (8) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees.
    (9) Payments for a volumetric deduction to cover shrinkage when 
high-gravity petroleum (generally in excess of 51 degrees API) is mixed 
with lower-gravity crude oil for transportation.
    (10) Costs of securing a letter of credit, or other surety, that 
the pipeline requires you as a shipper to maintain.
    (c) You may not deduct any costs that are not actual costs of 
transporting oil, including but not limited to the following:
    (1) Fees paid for long-term storage (more than 30 days).
    (2) Administrative, handling, and accounting fees associated with 
terminalling.
    (3) Title and terminal transfer fees.
    (4) Fees paid to track and match receipts and deliveries at a 
market center or to avoid paying title transfer fees.
    (5) Fees paid to brokers.
    (6) Fees paid to a scheduling service provider.
    (7) Internal costs, including salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to 
schedule, nominate, and account for sale or movement of production.
    (8) Gauging fees.
    (d) If your arm's-length transportation contract includes more than 
one liquid

[[Page 36960]]

product, and the transportation costs attributable to each product 
cannot be determined from the contract, then you must allocate the 
total transportation costs to each of the liquid products transported.
    (1) Your allocation must use the same proportion as the ratio of 
the volume of each product (excluding waste products with no value) to 
the volume of all liquid products (excluding waste products with no 
value).
    (2) You may not claim an allowance for the costs of transporting 
lease production that is not royalty-bearing.
    (3) You may propose to ONRR a cost allocation method on the basis 
of the values of the products transported. ONRR will approve the method 
unless it is not consistent with the purposes of the regulations in 
this subpart.
    (e) If your arm's-length transportation contract includes both 
gaseous and liquid products, and the transportation costs attributable 
to each product cannot be determined from the contract, then you must 
propose an allocation procedure to ONRR.
    (1) You may use your proposed procedure to calculate a 
transportation allowance until ONRR accepts or rejects your cost 
allocation. If ONRR rejects your cost allocation, you must amend your 
form ONRR-2014 for the months that you used the rejected method and pay 
any additional royalty and interest due.
    (2) You must submit your initial proposal, including all available 
data, within 3 months after first claiming the allocated deductions on 
form ONRR-2014.
    (f) If your payments for transportation under an arm's-length 
contract are not on a dollar-per-unit basis, you must convert whatever 
consideration is paid to a dollar-value equivalent.
    (g) If your arm's-length sales contract includes a provision 
reducing the contract price by a transportation factor, do not 
separately report the transportation factor as a transportation 
allowance on form ONRR-2014.
    (1) You may use the transportation factor in determining your gross 
proceeds for the sale of the product.
    (2) You must obtain ONRR approval before claiming a transportation 
factor in excess of 50 percent of the base price of the product.


Sec.  1206.111  How do I determine a transportation allowance if I do 
not have an arm's-length transportation contract or arm's-length 
tariff?

    (a) This section applies if you or your affiliate do not have an 
arm's-length transportation contract, including situations where you or 
your affiliate provide your own transportation services. Calculate your 
transportation allowance based on your or your affiliate's reasonable, 
actual costs for transportation during the reporting period using the 
procedures prescribed in this section.
    (b) Your or your affiliate's actual costs include the following:
    (1) Operating and maintenance expenses under paragraphs (d) and (e) 
of this section;
    (2) Overhead under paragraph (f) of this section;
    (3) Depreciation under paragraphs (g) and (h) of this section;
    (4) A return on undepreciated capital investment under paragraph 
(i) of this section; and
    (5) Once the transportation system has been depreciated below ten 
percent of total capital investment, a return on ten percent of total 
capital investment under paragraph (j) of this section.
    (6) To the extent not included in costs identified in paragraphs 
(d) through (j) of this section, you may also deduct the following 
actual costs. You may not use any cost as a deduction that duplicates 
all or part of any other cost that you use under this section:
    (i) Volumetric adjustments for actual (not theoretical) line 
losses.
    (ii) The cost of carrying on your books as inventory a volume of 
oil that the pipeline operator requires you as a shipper to maintain, 
and that you do maintain, in the line as line fill. You must calculate 
this cost as follows:
    (A) Multiply the volume that the pipeline requires you to maintain, 
and that you do maintain, in the pipeline by the value of that volume 
for the current month calculated under Sec.  1206.102 or Sec.  
1206.103, as applicable; and
    (B) Multiply the value calculated under paragraph (b)(6)(ii)(A) of 
this section by the monthly rate of return, calculated by dividing the 
rate of return specified in Sec.  1206.111(i)(2) by 12.
    (iii) Fees paid to a non-affiliated terminal operator for loading 
and unloading of crude oil into or from a vessel, vehicle, pipeline, or 
other conveyance.
    (iv) Transfer fees paid to a hub operator associated with physical 
movement of crude oil through the hub when you do not sell the oil at 
the hub. These fees do not include title transfer fees.
    (v) A volumetric deduction to cover shrinkage when high-gravity 
petroleum (generally in excess of 51 degrees API) is mixed with lower-
gravity crude oil for transportation.
    (vi) Fees paid to a non-affiliated quality bank administrator for 
administration of a quality bank.
    (7) You may not deduct any costs that are not actual costs of 
transporting oil, including but not limited to the following:
    (i) Fees paid for long-term storage (more than 30 days).
    (ii) Administrative, handling, and accounting fees associated with 
terminalling.
    (iii) Title and terminal transfer fees.
    (iv) Fees paid to track and match receipts and deliveries at a 
market center or to avoid paying title transfer fees.
    (v) Fees paid to brokers.
    (vi) Fees paid to a scheduling service provider.
    (vii) Internal costs, including salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to 
schedule, nominate, and account for sale or movement of production.
    (viii) Theoretical line losses.
    (ix) Gauging fees.
    (c) Allowable capital costs are generally those for depreciable 
fixed assets (including costs of delivery and installation of capital 
equipment) which are an integral part of the transportation system.
    (d) Allowable operating expenses include:
    (1) Operations supervision and engineering;
    (2) Operations labor;
    (3) Fuel;
    (4) Utilities;
    (5) Materials;
    (6) Ad valorem property taxes;
    (7) Rent;
    (8) Supplies; and
    (9) Any other directly allocable and attributable operating expense 
which you can document.
    (e) Allowable maintenance expenses include:
    (1) Maintenance of the transportation system;
    (2) Maintenance of equipment;
    (3) Maintenance labor; and
    (4) Other directly allocable and attributable maintenance expenses 
which you can document.
    (f) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (g) To compute depreciation, you may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, or a 
unit-of-production method. After you make an election, you may not 
change methods without

[[Page 36961]]

ONRR approval. You may not depreciate equipment below a reasonable 
salvage value.
    (h) This paragraph describes the basis for your depreciation 
schedule.
    (1) If you or your affiliate own a transportation system on June 1, 
2000, you must base your depreciation schedule used in calculating 
actual transportation costs for production after June 1, 2000, on your 
total capital investment in the system (including your original 
purchase price or construction cost and subsequent reinvestment).
    (2) If you or your affiliate purchased the transportation system at 
arm's length before June 1, 2000, you must incorporate depreciation on 
the schedule based on your purchase price (and subsequent reinvestment) 
into your transportation allowance calculations for production after 
June 1, 2000, beginning at the point on the depreciation schedule 
corresponding to that date. You must prorate your depreciation for 
calendar year 2000 by claiming part-year depreciation for the period 
from June 1, 2000 until December 31, 2000. You may not adjust your 
transportation costs for production before June 1, 2000, using the 
depreciation schedule based on your purchase price.
    (3) If you are the original owner of the transportation system on 
June 1, 2000, or if you purchased your transportation system before 
March 1, 1988, you must continue to use your existing depreciation 
schedule in calculating actual transportation costs for production in 
periods after June 1, 2000.
    (4) If you or your affiliate purchase a transportation system at 
arm's length from the original owner after June 1, 2000, you must base 
your depreciation schedule used in calculating actual transportation 
costs on your total capital investment in the system (including your 
original purchase price and subsequent reinvestment). You must prorate 
your depreciation for the year in which you or your affiliate purchased 
the system to reflect the portion of that year for which you or your 
affiliate own the system.
    (5) If you or your affiliate purchase a transportation system at 
arm's length after June 1, 2000, from anyone other than the original 
owner, you must assume the depreciation schedule of the person from 
whom you bought the system. Include in the depreciation schedule any 
subsequent reinvestment.
    (i)(1) To calculate a return on undepreciated capital investment, 
multiply the remaining undepreciated capital balance as of the 
beginning of the period for which you are calculating the 
transportation allowance by the rate of return provided in paragraph 
(i)(2) of this section.
    (2) The rate of return is 1.3 times the industrial bond yield index 
for Standard & Poor's BBB bond rating. Use the monthly average rate 
published in ``Standard & Poor's Bond Guide'' for the first month of 
the reporting period for which the allowance applies. Calculate the 
rate at the beginning of each subsequent transportation allowance 
reporting period.
    (j)(1) After a transportation system has been depreciated at or 
below a value equal to ten percent of your total capital investment, 
you may continue to include in the allowance calculation a cost equal 
to ten percent of your total capital investment in the transportation 
system multiplied by a rate of return under paragraph (i)(2) of this 
section.
    (2) You may apply this paragraph to a transportation system that 
before June 1, 2000, was depreciated at or below a value equal to ten 
percent of your total capital investment.
    (k) Calculate the deduction for transportation costs based on your 
or your affiliate's cost of transporting each product through each 
individual transportation system. Where more than one liquid product is 
transported, allocate costs consistently and equitably to each of the 
liquid products transported. Your allocation must use the same 
proportion as the ratio of the volume of each liquid product (excluding 
waste products with no value) to the volume of all liquid products 
(excluding waste products with no value).
    (1) You may not take an allowance for transporting lease production 
that is not royalty-bearing.
    (2) You may propose to ONRR a cost allocation method on the basis 
of the values of the products transported. ONRR will approve the method 
if it is consistent with the purposes of the regulations in this 
subpart.
    (l)(1) Where you transport both gaseous and liquid products through 
the same transportation system, you must propose a cost allocation 
procedure to ONRR.
    (2) You may use your proposed procedure to calculate a 
transportation allowance until ONRR accepts or rejects your cost 
allocation. If ONRR rejects your cost allocation, you must amend your 
form ONRR-2014 for the months that you used the rejected method and pay 
any additional royalty and interest due.
    (3) You must submit your initial proposal, including all available 
data, within 3 months after first claiming the allocated deductions on 
form ONRR-2014.


Sec.  [thinsp]1206.112  What adjustments and transportation allowances 
apply when I value oil production from my lease using NYMEX prices or 
ANS spot prices?

    This section applies when you use NYMEX prices or ANS spot prices 
to calculate the value of production under Sec.  [thinsp]1206.103. As 
specified in this section, adjust the NYMEX price to reflect the 
difference in value between your lease and Cushing, Oklahoma, or adjust 
the ANS spot price to reflect the difference in value between your 
lease and the appropriate ONRR-recognized market center at which the 
ANS spot price is published (for example, Long Beach, California, or 
San Francisco, California). Paragraph (a) of this section explains how 
you adjust the value between the lease and the market center, and 
paragraph (b) of this section explains how you adjust the value between 
the market center and Cushing when you use NYMEX prices. Paragraph (c) 
of this section explains how adjustments may be made for quality 
differentials that are not accounted for through exchange agreements. 
Paragraph (d) of this section gives some examples. References in this 
section to ``you'' include your affiliates as applicable.
    (a) To adjust the value between the lease and the market center:
    (1)(i) For oil that you exchange at arm's length between your lease 
and the market center (or between any intermediate points between those 
locations), you must calculate a lease-to-market center differential by 
the applicable location and quality differentials derived from your 
arm's-length exchange agreement applicable to production during the 
production month.
    (ii) For oil that you exchange between your lease and the market 
center (or between any intermediate points between those locations) 
under an exchange agreement that is not at arm's length, you must 
obtain approval from ONRR for a location and quality differential. 
Until you obtain such approval, you may use the location and quality 
differential derived from that exchange agreement applicable to 
production during the production month. If ONRR prescribes a different 
differential, you must apply ONRR's differential to all periods for 
which you used your proposed differential. You must pay any additional 
royalties owed resulting from using ONRR's differential plus late 
payment interest from the original royalty due date, or you may report 
a credit for any overpaid royalties plus interest under 30 U.S.C. 
1721(h).

[[Page 36962]]

    (2) For oil that you transport between your lease and the market 
center (or between any intermediate points between those locations), 
you may take an allowance for the cost of transporting that oil between 
the relevant points as determined under Sec.  [thinsp]1206.110 or Sec.  
[thinsp]1206.111, as applicable.
    (3) If you transport or exchange at arm's length (or both transport 
and exchange) at least 20 percent, but not all, of your oil produced 
from the lease to a market center, determine the adjustment between the 
lease and the market center for the oil that is not transported or 
exchanged (or both transported and exchanged) to or through a market 
center as follows:
    (i) Determine the volume-weighted average of the lease-to-market 
center adjustment calculated under paragraphs (a)(1) and (2) of this 
section for the oil that you do transport or exchange (or both 
transport and exchange) from your lease to a market center.
    (ii) Use that volume-weighted average lease-to-market center 
adjustment as the adjustment for the oil that you do not transport or 
exchange (or both transport and exchange) from your lease to a market 
center.
    (4) If you transport or exchange (or both transport and exchange) 
less than 20 percent of the crude oil produced from your lease between 
the lease and a market center, you must propose to ONRR an adjustment 
between the lease and the market center for the portion of the oil that 
you do not transport or exchange (or both transport and exchange) to a 
market center. Until you obtain such approval, you may use your 
proposed adjustment. If ONRR prescribes a different adjustment, you 
must apply ONRR's adjustment to all periods for which you used your 
proposed adjustment. You must pay any additional royalties owed 
resulting from using ONRR's adjustment plus late payment interest from 
the original royalty due date, or you may report a credit for any 
overpaid royalties plus interest under 30 U.S.C. 1721(h).
    (5) You may not both take a transportation allowance and use a 
location and quality adjustment or exchange differential for the same 
oil between the same points.
    (b) For oil that you value using NYMEX prices, adjust the value 
between the market center and Cushing, Oklahoma, as follows:
    (1) If you have arm's-length exchange agreements between the market 
center and Cushing under which you exchange to Cushing at least 20 
percent of all the oil you own at the market center during the 
production month, you must use the volume-weighted average of the 
location and quality differentials from those agreements as the 
adjustment between the market center and Cushing for all the oil that 
you produce from the leases during that production month for which that 
market center is used.
    (2) If paragraph (b)(1) of this section does not apply, you must 
use the WTI differential published in an ONRR-approved publication for 
the market center nearest your lease, for crude oil most similar in 
quality to your production, as the adjustment between the market center 
and Cushing. (For example, for light sweet crude oil produced offshore 
of Louisiana, use the WTI differential for Light Louisiana Sweet crude 
oil at St. James, Louisiana.) After you select an ONRR-approved 
publication, you may not select a different publication more often than 
once every 2 years, unless the publication you use is no longer 
published or ONRR revokes its approval of the publication. If you are 
required to change publications, you must begin a new 2-year period.
    (3) If neither paragraph (b)(1) nor (b)(2) of this section applies, 
you may propose an alternative differential to ONRR. Until you obtain 
such approval, you may use your proposed differential. If ONRR 
prescribes a different differential, you must apply ONRR's differential 
to all periods for which you used your proposed differential. You must 
pay any additional royalties owed resulting from using ONRR's 
differential plus late payment interest from the original royalty due 
date, or you may report a credit for any overpaid royalties plus 
interest under 30 U.S.C. 1721(h).
    (c)(1) If you adjust for location and quality differentials or for 
transportation costs under paragraphs (a) and (b) of this section, also 
adjust the NYMEX price or ANS spot price for quality based on premiums 
or penalties determined by pipeline quality bank specifications at 
intermediate commingling points or at the market center if those points 
are downstream of the royalty measurement point approved by BSEE or 
BLM, as applicable. Make this adjustment only if and to the extent that 
such adjustments were not already included in the location and quality 
differentials determined from your arm's-length exchange agreements.
    (2) If the quality of your oil as adjusted is still different from 
the quality of the representative crude oil at the market center after 
making the quality adjustments described in paragraphs (a), (b), and 
(c)(1) of this section, you may make further gravity adjustments using 
posted price gravity tables. If quality bank adjustments do not 
incorporate or provide for adjustments for sulfur content, you may make 
sulfur adjustments, based on the quality of the representative crude 
oil at the market center, of 5.0 cents per one-tenth percent difference 
in sulfur content, unless ONRR approves a higher adjustment.
    (d) The examples in this paragraph illustrate how to apply the 
requirement of this section.
    (1) Example. Assume that a Federal lessee produces crude oil from a 
lease near Artesia, New Mexico. Further, assume that the lessee 
transports the oil to Roswell, New Mexico, and then exchanges the oil 
to Midland, Texas. Assume the lessee refines the oil received in 
exchange at Midland. Assume that the NYMEX price is $30.00/bbl, 
adjusted for the roll; that the WTI differential (Cushing to Midland) 
is -$.10/bbl; that the lessee's exchange agreement between Roswell and 
Midland results in a location and quality differential of -$.08/bbl; 
and that the lessee's actual cost of transporting the oil from Artesia 
to Roswell is $.40/bbl. In this example, the royalty value of the oil 
is $30.00-$.10-$.08--$.40 = $29.42/bbl.
    (2) Example. Assume the same facts as in the example in paragraph 
(d)(1) of this section, except that the lessee transports and exchanges 
to Midland 40 percent of the production from the lease near Artesia, 
and transports the remaining 60 percent directly to its own refinery in 
Ohio. In this example, the 40 percent of the production would be valued 
at $29.42/bbl, as explained in the previous example. In this example, 
the other 60 percent also would be valued at $29.42/bbl.
    (3) Example. Assume that a Federal lessee produces crude oil from a 
lease near Bakersfield, California. Further, assume that the lessee 
transports the oil to Hynes Station, and then exchanges the oil to 
Cushing which it further exchanges with oil it refines. Assume that the 
ANS spot price is $20.00/bbl, and that the lessee's actual cost of 
transporting the oil from Bakersfield to Hynes Station is $.28/bbl. The 
lessee must request approval from ONRR for a location and quality 
adjustment between Hynes Station and Long Beach. For example, the 
lessee likely would propose using the tariff on Line 63 from Hynes 
Station to Long Beach as the adjustment between those points. Assume 
that adjustment to be $.72, including the sulfur and gravity bank 
adjustments, and that ONRR approves the lessee's request. In this 
example, the preliminary (because the location and quality adjustment 
is subject to ONRR review) royalty value of the oil is

[[Page 36963]]

$20.00-$.72-$.28 = $19.00/bbl. The fact that oil was exchanged to 
Cushing does not change use of ANS spot prices for royalty valuation.


Sec.  [thinsp]1206.113  How will ONRR identify market centers?

    ONRR periodically will publish in the Federal Register a list of 
market centers. ONRR will monitor market activity and, if necessary, 
add to or modify the list of market centers and will publish such 
modifications in the Federal Register. ONRR will consider the following 
factors and conditions in specifying market centers:
    (a) Points where ONRR-approved publications publish prices useful 
for index purposes;
    (b) Markets served;
    (c) Input from industry and others knowledgeable in crude oil 
marketing and transportation;
    (d) Simplification; and
    (e) Other relevant matters.


Sec.  [thinsp]1206.114  What are my reporting requirements under an 
arm's-length transportation contract?

    You or your affiliate must use a separate entry on form ONRR-2014 
to notify ONRR of an allowance based on transportation costs you or 
your affiliate incur. ONRR may require you or your affiliate to submit 
arm's-length transportation contracts, production agreements, operating 
agreements, and related documents. Recordkeeping requirements are found 
at part 1207 of this chapter.


Sec.  [thinsp]1206.115  What are my reporting requirements under a non-
arm's-length transportation arrangement?

    (a) You or your affiliate must use a separate entry on form ONRR-
2014 to notify ONRR of an allowance based on transportation costs you 
or your affiliate incur.
    (b) For new transportation facilities or arrangements, base your 
initial deduction on estimates of allowable oil transportation costs 
for the applicable period. Use the most recently available operations 
data for the transportation system or, if such data are not available, 
use estimates based on data for similar transportation systems. Section 
1206.117 will apply when you amend your report based on your actual 
costs.
    (c) ONRR may require you or your affiliate to submit all data used 
to calculate the allowance deduction. Recordkeeping requirements are 
found at part 1207 of this chapter.


Sec.  [thinsp]1206.116  What interest applies if I improperly report a 
transportation allowance?

    (a) If you or your affiliate deducts a transportation allowance on 
form ONRR-2014 that exceeds 50 percent of the value of the oil 
transported without obtaining ONRR's prior approval under Sec.  
[thinsp]1206.109, you must pay interest on the excess allowance amount 
taken from the date that amount is taken to the date you or your 
affiliate files an exception request that ONRR approves. If you do not 
file an exception request, or if ONRR does not approve your request, 
you must pay interest on the excess allowance amount taken from the 
date that amount is taken until the date you pay the additional 
royalties owed.
    (b) If you or your affiliate takes a deduction for transportation 
on form ONRR-2014 by improperly netting an allowance against the oil 
instead of reporting the allowance as a separate entry, ONRR may assess 
a civil penalty under 30 CFR part 1241.


Sec.  [thinsp]1206.117  What reporting adjustments must I make for 
transportation allowances?

    (a) If your or your affiliate's actual transportation allowance is 
less than the amount you claimed on form ONRR-2014 for each month 
during the allowance reporting period, you must pay additional 
royalties plus interest computed under Sec.  [thinsp]1218.54 of this 
chapter from the date you took the deduction to the date you repay the 
difference.
    (b) If the actual transportation allowance is greater than the 
amount you claimed on form ONRR-2014 for any month during the allowance 
form reporting period, you are entitled to a credit plus interest under 
applicable rules.


Sec.  [thinsp]1206.119  How are royalty quantity and quality 
determined?

    (a) Compute royalties based on the quantity and quality of oil as 
measured at the point of settlement approved by BLM for onshore leases 
or BSEE for offshore leases.
    (b) If the value of oil determined under this subpart is based upon 
a quantity or quality different from the quantity or quality at the 
point of royalty settlement approved by the BLM for onshore leases or 
BSEE for offshore leases, adjust the value for those differences in 
quantity or quality.
    (c) Any actual loss that you may incur before the royalty 
settlement metering or measurement point is not subject to royalty if 
BLM or BSEE, as appropriate, determines that the loss is unavoidable.
    (d) Except as provided in paragraph (b) of this section, royalties 
are due on 100 percent of the volume measured at the approved point of 
royalty settlement. You may not claim a reduction in that measured 
volume for actual losses beyond the approved point of royalty 
settlement or for theoretical losses that are claimed to have taken 
place either before or after the approved point of royalty settlement.


Sec.  [thinsp]1206.120  How are operating allowances determined?

    BOEM may use an operating allowance for the purpose of computing 
payment obligations when specified in the notice of sale and the lease. 
BOEM will specify the allowance amount or formula in the notice of sale 
and in the lease agreement.

0
7. Revise subpart D to read as follows:
Subpart D--Federal Gas
Sec.
1206.150 Purpose and scope.
1206.151 Definitions.
1206.152 Valuation standards--unprocessed gas.
1206.153 Valuation standards--processed gas.
1206.154 Determination of quantities and qualities for computing 
royalties.
1206.155 Accounting for comparison.
1206.156 Transportation allowances--general.
1206.157 Determination of transportation allowances.
1206.158 Processing allowances--general.
1206.159 Determination of processing allowances.
1206.160 Operating allowances.

Subpart D--Federal Gas


Sec.  [thinsp]1206.150  Purpose and scope.

    (a) This subpart is applicable to all gas production from Federal 
oil and gas leases. The purpose of this subpart is to establish the 
value of production for royalty purposes consistent with the mineral 
leasing laws, other applicable laws and lease terms.
    (b) If the regulations in this subpart are inconsistent with:
    (1) A Federal statute;
    (2) A settlement agreement between the United States and a lessee 
resulting from administrative or judicial litigation;
    (3) A written agreement between the lessee and the ONRR Director 
establishing a method to determine the value of production from any 
lease that ONRR expects at least would approximate the value 
established under this subpart; or
    (4) An express provision of an oil and gas lease subject to this 
subpart; then the statute, settlement agreement, written agreement, or 
lease provision will govern to the extent of the inconsistency.
    (c) All royalty payments made to ONRR are subject to audit and 
adjustment.
    (d) The regulations in this subpart are intended to ensure that the

[[Page 36964]]

administration of oil and gas leases is discharged in accordance with 
the requirements of the governing mineral leasing laws and lease terms.


Sec.  [thinsp]1206.151  Definitions.

    For purposes of this subpart:
    Affiliate means a person who controls, is controlled by, or is 
under common control with another person. For purposes of this subpart:
    (1) Ownership or common ownership of more than 50 percent of the 
voting securities, or instruments of ownership, or other forms of 
ownership, of another person constitutes control. Ownership of less 
than 10 percent constitutes a presumption of noncontrol that ONRR may 
rebut.
    (2) If there is ownership or common ownership of 10 through 50 
percent of the voting securities or instruments of ownership, or other 
forms of ownership, of another person, ONRR will consider the following 
factors in determining whether there is control under the circumstances 
of a particular case:
    (i) The extent to which there are common officers or directors;
    (ii) With respect to the voting securities, or instruments of 
ownership, or other forms of ownership: The percentage of ownership or 
common ownership, the relative percentage of ownership or common 
ownership compared to the percentage(s) of ownership by other persons, 
whether a person is the greatest single owner, or whether there is an 
opposing voting bloc of greater ownership;
    (iii) Operation of a lease, plant, pipeline, or other facility;
    (iv) The extent of participation by other owners in operations and 
day-to-day management of a lease, plant, pipeline, or other facility; 
and
    (v) Other evidence of power to exercise control over or common 
control with another person.
    (3) Regardless of any percentage of ownership or common ownership, 
relatives, either by blood or marriage, are affiliates.
    Allowance means a deduction in determining value for royalty 
purposes. Processing allowance means an allowance for the reasonable, 
actual costs of processing gas determined under this subpart. 
Transportation allowance means an allowance for the reasonable, actual 
costs of moving unprocessed gas, residue gas, or gas plant products to 
a point of sale or delivery off the lease, unit area, or communitized 
area, or away from a processing plant. The transportation allowance 
does not include gathering costs.
    Area means a geographic region at least as large as the defined 
limits of an oil and/or gas field, in which oil and/or gas lease 
products have similar quality, economic, and legal characteristics.
    Arm's-length contract means a contract or agreement between 
independent persons who are not affiliates and who have opposing 
economic interests regarding that contract. To be considered arm's 
length for any production month, a contract must satisfy this 
definition for that month, as well as when the contract was executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty payment 
compliance activities of lessees or other interest holders who pay 
royalties, rents, or bonuses on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    BOEM means the Bureau of Ocean Energy Management of the Department 
of the Interior.
    BSEE means the Bureau of Safety and Environmental Enforcement of 
the Department of the Interior.
    Compression means the process of raising the pressure of gas.
    Condensate means liquid hydrocarbons (normally exceeding 40 degrees 
of API gravity) recovered at the surface without resorting to 
processing. Condensate is the mixture of liquid hydrocarbons that 
results from condensation of petroleum hydrocarbons existing initially 
in a gaseous phase in an underground reservoir.
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by 
law that with due consideration creates an obligation.
    Field means a geographic region situated over one or more 
subsurface oil and gas reservoirs encompassing at least the outermost 
boundaries of all oil and gas accumulations known to be within those 
reservoirs vertically projected to the land surface. Onshore fields are 
usually given names and their official boundaries are often designated 
by oil and gas regulatory agencies in the respective States in which 
the fields are located. Outer Continental Shelf (OCS) fields are named 
and their boundaries are designated by BOEM.
    Gas means any fluid, either combustible or noncombustible, 
hydrocarbon or nonhydrocarbon, which is extracted from a reservoir and 
which has neither independent shape nor volume, but tends to expand 
indefinitely. It is a substance that exists in a gaseous or rarefied 
state under standard temperature and pressure conditions.
    Gas plant products means separate marketable elements, compounds, 
or mixtures, whether in liquid, gaseous, or solid form, resulting from 
processing gas, excluding residue gas.
    Gathering means the movement of lease production to a central 
accumulation and/or treatment point on the lease, unit or communitized 
area, or to a central accumulation or treatment point off the lease, 
unit or communitized area as approved by BLM or BSEE OCS operations 
personnel for onshore and OCS leases, respectively.
    Gross proceeds (for royalty payment purposes) means the total 
monies and other consideration accruing to an oil and gas lessee for 
the disposition of the gas, residue gas, and gas plant products 
produced. Gross proceeds includes, but is not limited to, payments to 
the lessee for certain services such as dehydration, measurement, and/
or gathering to the extent that the lessee is obligated to perform them 
at no cost to the Federal Government. Tax reimbursements are part of 
the gross proceeds accruing to a lessee even though the Federal royalty 
interest may be exempt from taxation. Monies and other consideration, 
including the forms of consideration identified in this paragraph, to 
which a lessee is contractually or legally entitled but which it does 
not seek to collect through reasonable efforts are also part of gross 
proceeds.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States under a 
mineral leasing law that authorizes exploration for, development or 
extraction of, or removal of lease products--or the land area covered 
by that authorization, whichever is required by the context.
    Lease products means any leased minerals attributable to, 
originating from, or allocated to Outer Continental Shelf or onshore 
Federal leases.
    Lessee means any person to whom the United States issues a lease, 
and any person who has been assigned an obligation to make royalty or 
other payments required by the lease. This includes any person who has 
an interest in a lease as well as an operator or payor who has no 
interest in the lease but who has assumed the royalty payment 
responsibility.
    Like-quality lease products means lease products which have similar 
chemical, physical, and legal characteristics.

[[Page 36965]]

    Marketable condition means lease products which are sufficiently 
free from impurities and otherwise in a condition that they will be 
accepted by a purchaser under a sales contract typical for the field or 
area.
    Marketing affiliate means an affiliate of the lessee whose function 
is to acquire only the lessee's production and to market that 
production.
    Minimum royalty means that minimum amount of annual royalty that 
the lessee must pay as specified in the lease or in applicable leasing 
regulations.
    Net-back method (or work-back method) means a method for 
calculating market value of gas at the lease. Under this method, costs 
of transportation, processing, or manufacturing are deducted from the 
proceeds received for the gas, residue gas or gas plant products, and 
any extracted, processed, or manufactured products, or from the value 
of the gas, residue gas or gas plant products, and any extracted, 
processed, or manufactured products, at the first point at which 
reasonable values for any such products may be determined by a sale 
pursuant to an arm's-length contract or comparison to other sales of 
such products, to ascertain value at the lease.
    Net output means the quantity of residue gas and each gas plant 
product that a processing plant produces.
    Net profit share (for applicable Federal leases) means the 
specified share of the net profit from production of oil and gas as 
provided in the agreement.
    Netting means the deduction of an allowance from the sales value by 
reporting a net sales value, instead of correctly reporting the 
deduction as a separate entry on form ONRR-2014.
    Outer Continental Shelf (OCS) means all submerged lands lying 
seaward and outside of the area of land beneath navigable waters as 
defined in section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of 
which the subsoil and seabed appertain to the United States and are 
subject to its jurisdiction and control.
    Person means any individual, firm, corporation, association, 
partnership, consortium, or joint venture (when established as a 
separate entity).
    Posted price means the price, net of all adjustments for quality 
and location, specified in publicly available price bulletins or other 
price notices available as part of normal business operations for 
quantities of unprocessed gas, residue gas, or gas plant products in 
marketable condition.
    Processing means any process designed to remove elements or 
compounds (hydrocarbon and nonhydrocarbon) from gas, including 
absorption, adsorption, or refrigeration. Field processes which 
normally take place on or near the lease, such as natural pressure 
reduction, mechanical separation, heating, cooling, dehydration, and 
compression, are not considered processing. The changing of pressures 
and/or temperatures in a reservoir is not considered processing.
    Residue gas means that hydrocarbon gas consisting principally of 
methane resulting from processing gas.
    Sales type code means the contract type or general disposition 
(e.g., arm's-length or non-arm's-length) of production from the lease. 
The sales type code applies to the sales contract, or other 
disposition, and not to the arm's-length or non-arm's-length nature of 
a transportation or processing allowance.
    Section 6 lease means an OCS lease subject to section 6 of the 
Outer Continental Shelf Lands Act, as amended, 43 U.S.C. 1335.
    Spot sales agreement means a contract wherein a seller agrees to 
sell to a buyer a specified amount of unprocessed gas, residue gas, or 
gas plant products at a specified price over a fixed period, usually of 
short duration, which does not normally require a cancellation notice 
to terminate, and which does not contain an obligation, nor imply an 
intent, to continue in subsequent periods.
    Warranty contract means a long-term contract entered into prior to 
1970, including any amendments thereto, for the sale of gas wherein the 
producer agrees to sell a specific amount of gas and the gas delivered 
in satisfaction of this obligation may come from fields or sources 
outside of the designated fields.


Sec.  [thinsp]1206.152  Valuation standards--unprocessed gas.

    (a)(1) This section applies to the valuation of all gas that is not 
processed and all gas that is processed but is sold or otherwise 
disposed of by the lessee pursuant to an arm's-length contract prior to 
processing (including all gas where the lessee's arm's-length contract 
for the sale of that gas prior to processing provides for the value to 
be determined on the basis of a percentage of the purchaser's proceeds 
resulting from processing the gas). This section also applies to 
processed gas that must be valued prior to processing in accordance 
with Sec.  [thinsp]1206.155 of this part. Where the lessee's contract 
includes a reservation of the right to process the gas and the lessee 
exercises that right, Sec.  [thinsp]1206.153 of this part shall apply 
instead of this section.
    (2) The value of production, for royalty purposes, of gas subject 
to this subpart shall be the value of gas determined under this section 
less applicable allowances.
    (b)(1)(i) The value of gas sold under an arm's-length contract is 
the gross proceeds accruing to the lessee except as provided in 
paragraphs (b)(1)(ii), (iii), and (iv) of this section. The lessee 
shall have the burden of demonstrating that its contract is arm's-
length. The value which the lessee reports, for royalty purposes, is 
subject to monitoring, review, and audit. For purposes of this section, 
gas which is sold or otherwise transferred to the lessee's marketing 
affiliate and then sold by the marketing affiliate pursuant to an 
arm's-length contract shall be valued in accordance with this paragraph 
based upon the sale by the marketing affiliate. Also, where the 
lessee's arm's-length contract for the sale of gas prior to processing 
provides for the value to be determined based upon a percentage of the 
purchaser's proceeds resulting from processing the gas, the value of 
production, for royalty purposes, shall never be less than a value 
equivalent to 100 percent of the value of the residue gas attributable 
to the processing of the lessee's gas.
    (ii) In conducting reviews and audits, ONRR will examine whether 
the contract reflects the total consideration actually transferred 
either directly or indirectly from the buyer to the seller for the gas. 
If the contract does not reflect the total consideration, then the ONRR 
may require that the gas sold pursuant to that contract be valued in 
accordance with paragraph (c) of this section. Value may not be less 
than the gross proceeds accruing to the lessee, including the 
additional consideration.
    (iii) If the ONRR determines that the gross proceeds accruing to 
the lessee pursuant to an arm's-length contract do not reflect the 
reasonable value of the production because of misconduct by or between 
the contracting parties, or because the lessee otherwise has breached 
its duty to the lessor to market the production for the mutual benefit 
of the lessee and the lessor, then ONRR shall require that the gas 
production be valued pursuant to paragraph (c)(2) or (c)(3) of this 
section, and in accordance with the notification requirements of 
paragraph (e) of this section. When ONRR determines that the value may 
be unreasonable, ONRR will notify the lessee and give the lessee an 
opportunity to provide written information justifying the lessee's 
value.
    (iv) How to value over-delivered volumes under a cash-out program: 
This paragraph applies to situations where a pipeline purchases gas 
from a lessee

[[Page 36966]]

according to a cash-out program under a transportation contract. For 
all over-delivered volumes, the royalty value is the price the pipeline 
is required to pay for volumes within the tolerances for over-delivery 
specified in the transportation contract. Use the same value for 
volumes that exceed the over-delivery tolerances even if those volumes 
are subject to a lower price under the transportation contract. 
However, if ONRR determines that the price specified in the 
transportation contract for over-delivered volumes is unreasonably low, 
the lessee must value all over-delivered volumes under paragraph (c)(2) 
or (3) of this section.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, the value of gas sold pursuant to a warranty contract shall be 
determined by ONRR, and due consideration will be given to all 
valuation criteria specified in this section. The lessee must request a 
value determination in accordance with paragraph (g) of this section 
for gas sold pursuant to a warranty contract; provided, however, that 
any value determination for a warranty contract in effect on the 
effective date of these regulations shall remain in effect until 
modified by ONRR.
    (3) ONRR may require a lessee to certify that its arm's-length 
contract provisions include all of the consideration to be paid by the 
buyer, either directly or indirectly, for the gas.
    (c) The value of gas subject to this section which is not sold 
pursuant to an arm's-length contract shall be the reasonable value 
determined in accordance with the first applicable of the following 
methods:
    (1) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition other than by 
an arm's-length contract), provided that those gross proceeds are 
equivalent to the gross proceeds derived from, or paid under, 
comparable arm's-length contracts for purchases, sales, or other 
dispositions of like-quality gas in the same field (or, if necessary to 
obtain a reasonable sample, from the same area). In evaluating the 
comparability of arm's-length contracts for the purposes of these 
regulations, the following factors shall be considered: Price, time of 
execution, duration, market or markets served, terms, quality of gas, 
volume, and such other factors as may be appropriate to reflect the 
value of the gas;
    (2) A value determined by consideration of other information 
relevant in valuing like-quality gas, including gross proceeds under 
arm's-length contracts for like-quality gas in the same field or nearby 
fields or areas, posted prices for gas, prices received in arm's-length 
spot sales of gas, other reliable public sources of price or market 
information, and other information as to the particular lease operation 
or the saleability of the gas; or
    (3) A net-back method or any other reasonable method to determine 
value.
    (d)(1) Notwithstanding any other provisions of this section, except 
paragraph (h) of this section, if the maximum price permitted by 
Federal law at which gas may be sold is less than the value determined 
pursuant to this section, then ONRR shall accept such maximum price as 
the value. For purposes of this section, price limitations set by any 
State or local government shall not be considered as a maximum price 
permitted by Federal law.
    (2) The limitation prescribed in paragraph (d)(1) of this section 
shall not apply to gas sold pursuant to a warranty contract and valued 
pursuant to paragraph (b)(2) of this section.
    (e)(1) Where the value is determined pursuant to paragraph (c) of 
this section, the lessee shall retain all data relevant to the 
determination of royalty value. Such data shall be subject to review 
and audit, and ONRR will direct a lessee to use a different value if it 
determines that the reported value is inconsistent with the 
requirements of these regulations.
    (2) Any Federal lessee will make available upon request to the 
authorized ONRR or State representatives, to the Office of the 
Inspector General of the Department of the Interior, or other person 
authorized to receive such information, arm's-length sales and volume 
data for like-quality production sold, purchased or otherwise obtained 
by the lessee from the field or area or from nearby fields or areas.
    (3) A lessee shall notify ONRR if it has determined value pursuant 
to paragraph (c)(2) or (3) of this section. The notification shall be 
by letter to the ONRR Director for Office of Natural Resources Revenue 
or his/her designee. The letter shall identify the valuation method to 
be used and contain a brief description of the procedure to be 
followed. The notification required by this paragraph is a one-time 
notification due no later than the end of the month following the month 
the lessee first reports royalties on a form ONRR-2014 using a 
valuation method authorized by paragraph (c)(2) or (3) of this section, 
and each time there is a change in a method under paragraph (c)(2) or 
(3) of this section.
    (f) If ONRR determines that a lessee has not properly determined 
value, the lessee shall pay the difference, if any, between royalty 
payments made based upon the value it has used and the royalty payments 
that are due based upon the value established by ONRR. The lessee shall 
also pay interest on that difference computed pursuant to Sec.  
[thinsp]1218.54 of this chapter. If the lessee is entitled to a credit, 
ONRR will provide instructions for the taking of that credit.
    (g) The lessee may request a value determination from ONRR. In that 
event, the lessee shall propose to ONRR a value determination method, 
and may use that method in determining value for royalty purposes until 
ONRR issues its decision. The lessee shall submit all available data 
relevant to its proposal. The ONRR shall expeditiously determine the 
value based upon the lessee's proposal and any additional information 
ONRR deems necessary. In making a value determination ONRR may use any 
of the valuation criteria authorized by this subpart. That 
determination shall remain effective for the period stated therein. 
After ONRR issues its determination, the lessee shall make the 
adjustments in accordance with paragraph (f) of this section.
    (h) Notwithstanding any other provision of this section, under no 
circumstances shall the value of production for royalty purposes be 
less than the gross proceeds accruing to the lessee for lease 
production, less applicable allowances.
    (i) The lessee must place gas in marketable condition and market 
the gas for the mutual benefit of the lessee and the lessor at no cost 
to the Federal Government. Where the value established under this 
section is determined by a lessee's gross proceeds, that value will be 
increased to the extent that the gross proceeds have been reduced 
because the purchaser, or any other person, is providing certain 
services the cost of which ordinarily is the responsibility of the 
lessee to place the gas in marketable condition or to market the gas.
    (j) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims under its contract. If there 
is no contract revision or amendment, and the lessee fails to take 
proper or timely action to receive prices or benefits to which it is 
entitled, it must pay royalty at a value based upon that obtainable 
price or benefit. Contract revisions or amendments shall be in writing 
and signed by all parties to an arm's-length contract. If the lessee 
makes timely application for a price increase or benefit allowed under 
its contract but the purchaser refuses, and the lessee takes reasonable 
measures, which are documented, to force purchaser

[[Page 36967]]

compliance, the lessee will owe no additional royalties unless or until 
monies or consideration resulting from the price increase or additional 
benefits are received. This paragraph shall not be construed to permit 
a lessee to avoid its royalty payment obligation in situations where a 
purchaser fails to pay, in whole or in part or timely, for a quantity 
of gas.
    (k) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or other like process 
that results in a redetermination by ONRR of value under this section 
shall be considered final or binding as against the Federal Government 
or its beneficiaries until the audit period is formally closed.
    (l) Certain information submitted to ONRR to support valuation 
proposals, including transportation or extraordinary cost allowances, 
is exempted from disclosure by the Freedom of Information Act, 5 U.S.C. 
552, or other Federal law. Any data specified by law to be privileged, 
confidential, or otherwise exempt will be maintained in a confidential 
manner in accordance with applicable law and regulations. All requests 
for information about determinations made under this subpart are to be 
submitted in accordance with the Freedom of Information Act regulation 
of the Department of the Interior, 43 CFR part 2.


Sec.  [thinsp]1206.153  Valuation standards--processed gas.

    (a)(1) This section applies to the valuation of all gas that is 
processed by the lessee and any other gas production to which this 
subpart applies and that is not subject to the valuation provisions of 
Sec.  1206.152 of this part. This section applies where the lessee's 
contract includes a reservation of the right to process the gas and the 
lessee exercises that right.
    (2) The value of production, for royalty purposes, of gas subject 
to this section shall be the combined value of the residue gas and all 
gas plant products determined pursuant to this section, plus the value 
of any condensate recovered downstream of the point of royalty 
settlement without resorting to processing determined pursuant to Sec.  
1206.102 of this part, less applicable transportation allowances and 
processing allowances determined pursuant to this subpart.
    (b)(1)(i) The value of residue gas or any gas plant product sold 
under an arm's-length contract is the gross proceeds accruing to the 
lessee, except as provided in paragraphs (b)(1)(ii), (iii), and (iv) of 
this section. The lessee shall have the burden of demonstrating that 
its contract is arm's-length. The value that the lessee reports for 
royalty purposes is subject to monitoring, review, and audit. For 
purposes of this section, residue gas or any gas plant product which is 
sold or otherwise transferred to the lessee's marketing affiliate and 
then sold by the marketing affiliate pursuant to an arm's-length 
contract shall be valued in accordance with this paragraph based upon 
the sale by the marketing affiliate.
    (ii) In conducting these reviews and audits, ONRR will examine 
whether or not the contract reflects the total consideration actually 
transferred either directly or indirectly from the buyer to the seller 
for the residue gas or gas plant product. If the contract does not 
reflect the total consideration, then the ONRR may require that the 
residue gas or gas plant product sold pursuant to that contract be 
valued in accordance with paragraph (c) of this section. Value may not 
be less than the gross proceeds accruing to the lessee, including the 
additional consideration.
    (iii) If the ONRR determines that the gross proceeds accruing to 
the lessee pursuant to an arm's-length contract do not reflect the 
reasonable value of the residue gas or gas plant product because of 
misconduct by or between the contracting parties, or because the lessee 
otherwise has breached its duty to the lessor to market the production 
for the mutual benefit of the lessee and the lessor, then ONRR shall 
require that the residue gas or gas plant product be valued pursuant to 
paragraph (c)(2) or (3) of this section, and in accordance with the 
notification requirements of paragraph (e) of this section. When ONRR 
determines that the value may be unreasonable, ONRR will notify the 
lessee and give the lessee an opportunity to provide written 
information justifying the lessee's value.
    (iv) How to value over-delivered volumes under a cash-out program: 
This paragraph applies to situations where a pipeline purchases gas 
from a lessee according to a cash-out program under a transportation 
contract. For all over-delivered volumes, the royalty value is the 
price the pipeline is required to pay for volumes within the tolerances 
for over-delivery specified in the transportation contract. Use the 
same value for volumes that exceed the over-delivery tolerances even if 
those volumes are subject to a lower price under the transportation 
contract. However, if ONRR determines that the price specified in the 
transportation contract for over-delivered volumes is unreasonably low, 
the lessee must value all over-delivered volumes under paragraph (c)(2) 
or (3) of this section.
    (2) Notwithstanding the provisions of paragraph (b)(1) of this 
section, the value of residue gas sold pursuant to a warranty contract 
shall be determined by ONRR, and due consideration will be given to all 
valuation criteria specified in this section. The lessee must request a 
value determination in accordance with paragraph (g) of this section 
for gas sold pursuant to a warranty contract; provided, however, that 
any value determination for a warranty contract in effect on the 
effective date of these regulations shall remain in effect until 
modified by ONRR.
    (3) ONRR may require a lessee to certify that its arm's-length 
contract provisions include all of the consideration to be paid by the 
buyer, either directly or indirectly, for the residue gas or gas plant 
product.
    (c) The value of residue gas or any gas plant product which is not 
sold pursuant to an arm's-length contract shall be the reasonable value 
determined in accordance with the first applicable of the following 
methods:
    (1) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition other than by 
an arm's-length contract), provided that those gross proceeds are 
equivalent to the gross proceeds derived from, or paid under, 
comparable arm's-length contracts for purchases, sales, or other 
dispositions of like quality residue gas or gas plant products from the 
same processing plant (or, if necessary to obtain a reasonable sample, 
from nearby plants). In evaluating the comparability of arm's-length 
contracts for the purposes of these regulations, the following factors 
shall be considered: Price, time of execution, duration, market or 
markets served, terms, quality of residue gas or gas plant products, 
volume, and such other factors as may be appropriate to reflect the 
value of the residue gas or gas plant products;
    (2) A value determined by consideration of other information 
relevant in valuing like-quality residue gas or gas plant products, 
including gross proceeds under arm's-length contracts for like-quality 
residue gas or gas plant products from the same gas plant or other 
nearby processing plants, posted prices for residue gas or gas plant 
products, prices received in spot sales of residue gas or gas plant 
products, other reliable public sources of price or market information, 
and other information as to the particular lease operation or the 
saleability of such residue gas or gas plant products; or
    (3) A net-back method or any other reasonable method to determine 
value.

[[Page 36968]]

    (d)(1) Notwithstanding any other provisions of this section, except 
paragraph (h) of this section, if the maximum price permitted by 
Federal law at which any residue gas or gas plant products may be sold 
is less than the value determined pursuant to this section, then ONRR 
shall accept such maximum price as the value. For the purposes of this 
section, price limitations set by any State or local government shall 
not be considered as a maximum price permitted by Federal law.
    (2) The limitation prescribed by paragraph (d)(1) of this section 
shall not apply to residue gas sold pursuant to a warranty contract and 
valued pursuant to paragraph (b)(2) of this section.
    (e)(1) Where the value is determined pursuant to paragraph (c) of 
this section, the lessee shall retain all data relevant to the 
determination of royalty value. Such data shall be subject to review 
and audit, and ONRR will direct a lessee to use a different value if it 
determines upon review or audit that the reported value is inconsistent 
with the requirements of these regulations.
    (2) Any Federal lessee will make available upon request to the 
authorized ONRR or State representatives, to the Office of the 
Inspector General of the Department of the Interior, or other persons 
authorized to receive such information, arm's-length sales and volume 
data for like-quality residue gas and gas plant products sold, 
purchased or otherwise obtained by the lessee from the same processing 
plant or from nearby processing plants.
    (3) A lessee shall notify ONRR if it has determined any value 
pursuant to paragraph (c)(2) or (3) of this section. The notification 
shall be by letter to the ONRR Director for Office of Natural Resources 
or his/her designee. The letter shall identify the valuation method to 
be used and contain a brief description of the procedure to be 
followed. The notification required by this paragraph is a one-time 
notification due no later than the end of the month following the month 
the lessee first reports royalties on a form ONRR-2014 using a 
valuation method authorized by paragraph (c)(2) or (3) of this section, 
and each time there is a change in a method under paragraph (c)(2) or 
(3) of this section.
    (f) If ONRR determines that a lessee has not properly determined 
value, the lessee shall pay the difference, if any, between royalty 
payments made based upon the value it has used and the royalty payments 
that are due based upon the value established by ONRR. The lessee shall 
also pay interest computed on that difference pursuant to Sec.  
[thinsp]1218.54 of this chapter. If the lessee is entitled to a credit, 
ONRR will provide instructions for the taking of that credit.
    (g) The lessee may request a value determination from ONRR. In that 
event, the lessee shall propose to ONRR a value determination method, 
and may use that method in determining value for royalty purposes until 
ONRR issues its decision. The lessee shall submit all available data 
relevant to its proposal. The ONRR shall expeditiously determine the 
value based upon the lessee's proposal and any additional information 
ONRR deems necessary. In making a value determination, ONRR may use any 
of the valuation criteria authorized by this subpart. That 
determination shall remain effective for the period stated therein. 
After ONRR issues its determination, the lessee shall make the 
adjustments in accordance with paragraph (f) of this section.
    (h) Notwithstanding any other provision of this section, under no 
circumstances shall the value of production for royalty purposes be 
less than the gross proceeds accruing to the lessee for residue gas 
and/or any gas plant products, less applicable transportation 
allowances and processing allowances determined pursuant to this 
subpart.
    (i) The lessee must place residue gas and gas plant products in 
marketable condition and market the residue gas and gas plant products 
for the mutual benefit of the lessee and the lessor at no cost to the 
Federal Government. Where the value established under this section is 
determined by a lessee's gross proceeds, that value will be increased 
to the extent that the gross proceeds have been reduced because the 
purchaser, or any other person, is providing certain services the cost 
of which ordinarily is the responsibility of the lessee to place the 
residue gas or gas plant products in marketable condition or to market 
the residue gas and gas plant products.
    (j) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims under its contract. Absent 
contract revision or amendment, if the lessee fails to take proper or 
timely action to receive prices or benefits to which it is entitled it 
must pay royalty at a value based upon that obtainable price or 
benefit. Contract revisions or amendments shall be in writing and 
signed by all parties to an arm's-length contract. If the lessee makes 
timely application for a price increase or benefit allowed under its 
contract but the purchaser refuses, and the lessee takes reasonable 
measures, which are documented, to force purchaser compliance, the 
lessee will owe no additional royalties unless or until monies or 
consideration resulting from the price increase or additional benefits 
are received. This paragraph shall not be construed to permit a lessee 
to avoid its royalty payment obligation in situations where a purchaser 
fails to pay, in whole or in part, or timely, for a quantity of residue 
gas or gas plant product.
    (k) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or other like process 
that results in a redetermination by ONRR of value under this section 
shall be considered final or binding against the Federal Government or 
its beneficiaries until the audit period is formally closed.
    (l) Certain information submitted to ONRR to support valuation 
proposals, including transportation allowances, processing allowances 
or extraordinary cost allowances, is exempted from disclosure by the 
Freedom of Information Act, 5 U.S.C. 552, or other Federal law. Any 
data specified by law to be privileged, confidential, or otherwise 
exempt, will be maintained in a confidential manner in accordance with 
applicable law and regulations. All requests for information about 
determinations made under this part are to be submitted in accordance 
with the Freedom of Information Act regulation of the Department of the 
Interior, 43 CFR part 2.


Sec.  [thinsp]1206.154  Determination of quantities and qualities for 
computing royalties.

    (a)(1) Royalties shall be computed on the basis of the quantity and 
quality of unprocessed gas at the point of royalty settlement approved 
by BLM or BSEE for onshore and OCS leases, respectively.
    (2) If the value of gas determined pursuant to Sec.  
[thinsp]1206.152 of this subpart is based upon a quantity and/or 
quality that is different from the quantity and/or quality at the point 
of royalty settlement, as approved by BLM or BSEE, that value shall be 
adjusted for the differences in quantity and/or quality.
    (b)(1) For residue gas and gas plant products, the quantity basis 
for computing royalties due is the monthly net output of the plant even 
though residue gas and/or gas plant products may be in temporary 
storage.
    (2) If the value of residue gas and/or gas plant products 
determined pursuant to Sec.  [thinsp]1206.153 of this subpart is based 
upon a quantity and/or quality of residue gas and/or gas plant products 
that is different from that which is attributable to a lease, 
determined in accordance with paragraph (c) of this section, that value 
shall be adjusted for

[[Page 36969]]

the differences in quantity and/or quality.
    (c) The quantity of the residue gas and gas plant products 
attributable to a lease shall be determined according to the following 
procedure:
    (1) When the net output of the processing plant is derived from gas 
obtained from only one lease, the quantity of the residue gas and gas 
plant products on which computations of royalty are based is the net 
output of the plant.
    (2) When the net output of a processing plant is derived from gas 
obtained from more than one lease producing gas of uniform content, the 
quantity of the residue gas and gas plant products allocable to each 
lease shall be in the same proportions as the ratios obtained by 
dividing the amount of gas delivered to the plant from each lease by 
the total amount of gas delivered from all leases.
    (3) When the net output of a processing plant is derived from gas 
obtained from more than one lease producing gas of nonuniform content, 
the quantity of the residue gas allocable to each lease will be 
determined by multiplying the amount of gas delivered to the plant from 
the lease by the residue gas content of the gas, and dividing the 
arithmetical product thus obtained by the sum of the similar 
arithmetical products separately obtained for all leases from which gas 
is delivered to the plant, and then multiplying the net output of the 
residue gas by the arithmetic quotient obtained. The net output of gas 
plant products allocable to each lease will be determined by 
multiplying the amount of gas delivered to the plant from the lease by 
the gas plant product content of the gas, and dividing the arithmetical 
product thus obtained by the sum of the similar arithmetical products 
separately obtained for all leases from which gas is delivered to the 
plant, and then multiplying the net output of each gas plant product by 
the arithmetic quotient obtained.
    (4) A lessee may request ONRR approval of other methods for 
determining the quantity of residue gas and gas plant products 
allocable to each lease. If approved, such method will be applicable to 
all gas production from Federal leases that is processed in the same 
plant.
    (d)(1) No deductions may be made from the royalty volume or royalty 
value for actual or theoretical losses. Any actual loss of unprocessed 
gas that may be sustained prior to the royalty settlement metering or 
measurement point will not be subject to royalty provided that such 
loss is determined to have been unavoidable by BLM or BSEE, as 
appropriate.
    (2) Except as provided in paragraph (d)(1) of this section and 
Sec.  [thinsp]1202.151(c), royalties are due on 100 percent of the 
volume determined in accordance with paragraphs (a) through (c) of this 
section. There can be no reduction in that determined volume for actual 
losses after the quantity basis has been determined or for theoretical 
losses that are claimed to have taken place. Royalties are due on 100 
percent of the value of the unprocessed gas, residue gas, and/or gas 
plant products as provided in this subpart, less applicable allowances. 
There can be no deduction from the value of the unprocessed gas, 
residue gas, and/or gas plant products to compensate for actual losses 
after the quantity basis has been determined, or for theoretical losses 
that are claimed to have taken place.


Sec.  [thinsp]1206.155  Accounting for comparison.

    (a) Except as provided in paragraph (b) of this section, where the 
lessee (or a person to whom the lessee has transferred gas pursuant to 
a non-arm's-length contract or without a contract) processes the 
lessee's gas and after processing the gas the residue gas is not sold 
pursuant to an arm's-length contract, the value, for royalty purposes, 
shall be the greater of:
    (1) The combined value, for royalty purposes, of the residue gas 
and gas plant products resulting from processing the gas determined 
pursuant to Sec.  [thinsp]1206.153 of this subpart, plus the value, for 
royalty purposes, of any condensate recovered downstream of the point 
of royalty settlement without resorting to processing determined 
pursuant to Sec.  [thinsp]1206.102 of this subpart; or
    (2) The value, for royalty purposes, of the gas prior to processing 
determined in accordance with Sec.  [thinsp]1206.152 of this subpart.
    (b) The requirement for accounting for comparison contained in the 
terms of leases will govern as provided in Sec.  [thinsp]1206.150(b) of 
this subpart. When accounting for comparison is required by the lease 
terms, such accounting for comparison shall be determined in accordance 
with paragraph (a) of this section.


Sec.  [thinsp]1206.156  Transportation allowances--general.

    (a) Where the value of gas has been determined pursuant to Sec.  
[thinsp]1206.152 or Sec.  [thinsp]1206.153 of this subpart at a point 
(e.g., sales point or point of value determination) off the lease, ONRR 
shall allow a deduction for the reasonable actual costs incurred by the 
lessee to transport unprocessed gas, residue gas, and gas plant 
products from a lease to a point off the lease including, if 
appropriate, transportation from the lease to a gas processing plant 
off the lease and from the plant to a point away from the plant.
    (b) Transportation costs must be allocated among all products 
produced and transported as provided in Sec.  [thinsp]1206.157.
    (c)(1) Except as provided in paragraph (c)(3) of this section, for 
unprocessed gas valued in accordance with Sec.  [thinsp]1206.152 of 
this subpart, the transportation allowance deduction on the basis of a 
sales type code may not exceed 50 percent of the value of the 
unprocessed gas determined under Sec.  [thinsp]1206.152 of this 
subpart.
    (2) Except as provided in paragraph (c)(3) of this section, for gas 
production valued in accordance with Sec.  [thinsp]1206.153 of this 
subpart, the transportation allowance deduction on the basis of a sales 
type code may not exceed 50 percent of the value of the residue gas or 
gas plant product determined under Sec.  [thinsp]1206.153 of this 
subpart. For purposes of this section, natural gas liquids will be 
considered one product.
    (3) Upon request of a lessee, ONRR may approve a transportation 
allowance deduction in excess of the limitations prescribed by 
paragraphs (c)(1) and (2) of this section. The lessee must demonstrate 
that the transportation costs incurred in excess of the limitations 
prescribed in paragraphs (c)(1) and (2) of this section were 
reasonable, actual, and necessary. An application for exception (using 
form ONRR-4393, Request to Exceed Regulatory Allowance Limitation) must 
contain all relevant and supporting documentation necessary for ONRR to 
make a determination. Under no circumstances may the value for royalty 
purposes under any sales type code be reduced to zero.
    (d) If, after a review or audit, ONRR determines that a lessee has 
improperly determined a transportation allowance authorized by this 
subpart, then the lessee must pay any additional royalties, plus 
interest, determined in accordance with Sec.  [thinsp]1218.54 of this 
chapter, or will be entitled to a credit, with interest. If the lessee 
takes a deduction for transportation on form ONRR-2014 by improperly 
netting the allowance against the sales value of the unprocessed gas, 
residue gas, and gas plant products instead of reporting the allowance 
as a separate entry, ONRR may assess a civil penalty under 30 CFR part 
1241.

[[Page 36970]]

Sec.  [thinsp]1206.157  Determination of transportation allowances.

    (a) Arm's-length transportation contracts. (1)(i) For 
transportation costs incurred by a lessee under an arm's-length 
contract, the transportation allowance shall be the reasonable, actual 
costs incurred by the lessee for transporting the unprocessed gas, 
residue gas and/or gas plant products under that contract, except as 
provided in paragraphs (a)(1)(ii) and (iii) of this section, subject to 
monitoring, review, audit, and adjustment. The lessee shall have the 
burden of demonstrating that its contract is arm's-length. ONRR's prior 
approval is not required before a lessee may deduct costs incurred 
under an arm's-length contract. Such allowances shall be subject to the 
provisions of paragraph (f) of this section. The lessee must claim a 
transportation allowance by reporting it as a separate entry on the 
form ONRR-2014.
    (ii) In conducting reviews and audits, ONRR will examine whether or 
not the contract reflects more than the consideration actually 
transferred either directly or indirectly from the lessee to the 
transporter for the transportation. If the contract reflects more than 
the total consideration, then the ONRR may require that the 
transportation allowance be determined in accordance with paragraph (b) 
of this section.
    (iii) If the ONRR determines that the consideration paid pursuant 
to an arm's-length transportation contract does not reflect the 
reasonable value of the transportation because of misconduct by or 
between the contracting parties, or because the lessee otherwise has 
breached its duty to the lessor to market the production for the mutual 
benefit of the lessee and the lessor, then ONRR shall require that the 
transportation allowance be determined in accordance with paragraph (b) 
of this section. When ONRR determines that the value of the 
transportation may be unreasonable, ONRR will notify the lessee and 
give the lessee an opportunity to provide written information 
justifying the lessee's transportation costs.
    (2)(i) If an arm's-length transportation contract includes more 
than one product in a gaseous phase and the transportation costs 
attributable to each product cannot be determined from the contract, 
the total transportation costs shall be allocated in a consistent and 
equitable manner to each of the products transported in the same 
proportion as the ratio of the volume of each product (excluding waste 
products which have no value) to the volume of all products in the 
gaseous phase (excluding waste products which have no value). Except as 
provided in this paragraph, no allowance may be taken for the costs of 
transporting lease production which is not royalty bearing without ONRR 
approval.
    (ii) Notwithstanding the requirements of paragraph (a)(2)(i) of 
this section, the lessee may propose to ONRR a cost allocation method 
on the basis of the values of the products transported. ONRR shall 
approve the method unless it determines that it is not consistent with 
the purposes of the regulations in this part.
    (3) If an arm's-length transportation contract includes both 
gaseous and liquid products and the transportation costs attributable 
to each cannot be determined from the contract, the lessee shall 
propose an allocation procedure to ONRR. The lessee may use the 
transportation allowance determined in accordance with its proposed 
allocation procedure until ONRR issues its determination on the 
acceptability of the cost allocation. The lessee shall submit all 
relevant data to support its proposal. ONRR shall then determine the 
gas transportation allowance based upon the lessee's proposal and any 
additional information ONRR deems necessary. The lessee must submit the 
allocation proposal within 3 months of claiming the allocated deduction 
on the form ONRR-2014.
    (4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar per unit, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent for 
the purposes of this section.
    (5) Where an arm's-length sales contract price or a posted price 
includes a provision whereby the listed price is reduced by a 
transportation factor, ONRR will not consider the transportation factor 
to be a transportation allowance. The transportation factor may be used 
in determining the lessee's gross proceeds for the sale of the product. 
The transportation factor may not exceed 50 percent of the base price 
of the product without ONRR approval.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length transportation contract or has no contract, including 
those situations where the lessee performs transportation services for 
itself, the transportation allowance will be based upon the lessee's 
reasonable actual costs as provided in this paragraph. All 
transportation allowances deducted under a non-arm's-length or no 
contract situation are subject to monitoring, review, audit, and 
adjustment. The lessee must claim a transportation allowance by 
reporting it as a separate entry on the form ONRR-2014. When necessary 
or appropriate, ONRR may direct a lessee to modify its estimated or 
actual transportation allowance deduction.
    (2) The transportation allowance for non-arm's-length or no-
contract situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the initial 
depreciable investment in the transportation system multiplied by a 
rate of return in accordance with paragraph (b)(2)(iv)(B) of this 
section. Allowable capital costs are generally those costs for 
depreciable fixed assets (including costs of delivery and installation 
of capital equipment) which are an integral part of the transportation 
system.
    (i) Allowable operating expenses include: Operations supervision 
and engineering; operations labor; fuel; utilities; materials; ad 
valorem property taxes; rent; supplies; and any other directly 
allocable and attributable operating expense which the lessee can 
document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which 
the lessee can document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the transportation system is an allowable expense. 
State and Federal income taxes and severance taxes and other fees, 
including royalties, are not allowable expenses.
    (iv) A lessee may use either depreciation or a return on 
depreciable capital investment. After a lessee has elected to use 
either method for a transportation system, the lessee may not later 
elect to change to the other alternative without approval of the ONRR.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, or a 
unit of production method. After an election is made, the lessee may 
not change methods without ONRR approval. A change in ownership of a 
transportation system shall not alter the depreciation schedule 
established by the original transporter/lessee for purposes of the 
allowance calculation.

[[Page 36971]]

With or without a change in ownership, a transportation system shall be 
depreciated only once. Equipment shall not be depreciated below a 
reasonable salvage value.
    (B) The ONRR shall allow as a cost an amount equal to the allowable 
initial capital investment in the transportation system multiplied by 
the rate of return determined pursuant to paragraph (b)(2)(v) of this 
section. No allowance shall be provided for depreciation. This 
alternative shall apply only to transportation facilities first placed 
in service after March 1, 1988.
    (v) The rate of return must be 1.3 times the industrial rate 
associated with Standard & Poor's BBB rating. The BBB rate must be the 
monthly average rate as published in Standard & Poor's Bond Guide for 
the first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3)(i) The deduction for transportation costs shall be determined 
on the basis of the lessee's cost of transporting each product through 
each individual transportation system. Where more than one product in a 
gaseous phase is transported, the allocation of costs to each of the 
products transported shall be made in a consistent and equitable manner 
in the same proportion as the ratio of the volume of each product 
(excluding waste products which have no value) to the volume of all 
products in the gaseous phase (excluding waste products which have no 
value). Except as provided in this paragraph, the lessee may not take 
an allowance for transporting a product which is not royalty bearing 
without ONRR approval.
    (ii) Notwithstanding the requirements of paragraph (b)(3)(i) of 
this section, the lessee may propose to the ONRR a cost allocation 
method on the basis of the values of the products transported. ONRR 
shall approve the method unless it determines that it is not consistent 
with the purposes of the regulations in this part.
    (4) Where both gaseous and liquid products are transported through 
the same transportation system, the lessee shall propose a cost 
allocation procedure to ONRR. The lessee may use the transportation 
allowance determined in accordance with its proposed allocation 
procedure until ONRR issues its determination on the acceptability of 
the cost allocation. The lessee shall submit all relevant data to 
support its proposal. ONRR shall then determine the transportation 
allowance based upon the lessee's proposal and any additional 
information ONRR deems necessary. The lessee must submit the allocation 
proposal within 3 months of claiming the allocated deduction on the 
form ONRR-2014.
    (5) You may apply for an exception from the requirement to compute 
actual costs under paragraphs (b)(1) through (4) of this section.
    (i) ONRR will grant the exception if:
    (A) The transportation system has a tariff filed with the Federal 
Energy Regulatory Commission (FERC) or a State regulatory agency, that 
FERC or the State regulatory agency has permitted to become effective, 
and
    (B) Third parties are paying prices, including discounted prices, 
under the tariff to transport gas on the system under arm's-length 
transportation contracts.
    (ii) If ONRR approves the exception, you must calculate your 
transportation allowance for each production month based on the lesser 
of the volume-weighted average of the rates paid by the third parties 
under arm's-length transportation contracts during that production 
month or the non-arm's-length payment by the lessee to the pipeline.
    (iii) If during any production month there are no prices paid under 
the tariff by third parties to transport gas on the system under arm's-
length transportation contracts, you may use the volume-weighted 
average of the rates paid by third parties under arm's-length 
transportation contracts in the most recent preceding production month 
in which the tariff remains in effect and third parties paid such 
rates, for up to five successive production months. You must use the 
non-arm's-length payment by the lessee to the pipeline if it is less 
than the volume-weighted average of the rates paid by third parties 
under arm's-length contracts.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) You 
must use a separate entry on form ONRR-2014 to notify ONRR of a 
transportation allowance.
    (ii) ONRR may require you to submit arm's-length transportation 
contracts, production agreements, operating agreements, and related 
documents. Recordkeeping requirements are found at part 1207 of this 
chapter.
    (iii) You may not use a transportation allowance that was in effect 
before March 1, 1988. You must use the provisions of this subpart to 
determine your transportation allowance.
    (2) Non-arm's-length or no contract. (i) You must use a separate 
entry on form ONRR-2014 to notify ONRR of a transportation allowance.
    (ii) For new transportation facilities or arrangements, base your 
initial deduction on estimates of allowable gas transportation costs 
for the applicable period. Use the most recently available operations 
data for the transportation system or, if such data are not available, 
use estimates based on data for similar transportation systems. 
Paragraph (e) of this section will apply when you amend your report 
based on your actual costs.
    (iii) ONRR may require you to submit all data used to calculate the 
allowance deduction. Recordkeeping requirements are found at part 1207 
of this chapter.
    (iv) If you are authorized under paragraph (b)(5) of this section 
to use an exception to the requirement to calculate your actual 
transportation costs, you must follow the reporting requirements of 
paragraph (c)(1) of this section.
    (v) You may not use a transportation allowance that was in effect 
before March 1, 1988. You must use the provisions of this subpart to 
determine your transportation allowance.
    (d) Interest and assessments. (1) If a lessee deducts a 
transportation allowance on its form ONRR-2014 that exceeds 50 percent 
of the value of the gas transported without obtaining prior approval of 
ONRR under Sec.  1206.156, the lessee shall pay interest on the excess 
allowance amount taken from the date such amount is taken to the date 
the lessee files an exception request with ONRR.
    (2) If a lessee erroneously reports a transportation allowance 
which results in an underpayment of royalties, interest shall be paid 
on the amount of that underpayment.
    (3) Interest required to be paid by this section shall be 
determined in accordance with Sec.  1218.54 of this chapter.
    (e) Adjustments. (1) If the actual transportation allowance is less 
than the amount the lessee has taken on form ONRR-2014 for each month 
during the allowance reporting period, the lessee shall be required to 
pay additional royalties due plus interest computed under Sec.  1218.54 
of this chapter from the allowance reporting period when the lessee 
took the deduction to the date the lessee repays the difference to 
ONRR. If the actual transportation allowance is greater than the amount 
the lessee has taken on form ONRR-2014 for each month during the 
allowance reporting period, the lessee shall be entitled to a credit 
without interest.
    (2) For lessees transporting production from onshore Federal 
leases, the lessee must submit a corrected form ONRR-2014 to reflect 
actual costs, together with any payment, in accordance with 
instructions provided by ONRR.

[[Page 36972]]

    (3) For lessees transporting gas production from leases on the OCS, 
if the lessee's estimated transportation allowance exceeds the 
allowance based on actual costs, the lessee must submit a corrected 
form ONRR-2014 to reflect actual costs, together with its payment, in 
accordance with instructions provided by ONRR. If the lessee's 
estimated transportation allowance is less than the allowance based on 
actual costs, the refund procedure will be specified by ONRR.
    (f) Allowable costs in determining transportation allowances. You 
may include, but are not limited to (subject to the requirements of 
paragraph (g) of this section), the following costs in determining the 
arm's-length transportation allowance under paragraph (a) of this 
section or the non-arm's-length transportation allowance under 
paragraph (b) of this section. You may not use any cost as a deduction 
that duplicates all or part of any other cost that you use under this 
paragraph.
    (1) Firm demand charges paid to pipelines. You may deduct firm 
demand charges or capacity reservation fees paid to a pipeline, 
including charges or fees for unused firm capacity that you have not 
sold before you report your allowance. If you receive a payment from 
any party for release or sale of firm capacity after reporting a 
transportation allowance that included the cost of that unused firm 
capacity, or if you receive a payment or credit from the pipeline for 
penalty refunds, rate case refunds, or other reasons, you must reduce 
the firm demand charge claimed on the form ONRR-2014 by the amount of 
that payment. You must modify the form ONRR-2014 by the amount received 
or credited for the affected reporting period, and pay any resulting 
royalty and late payment interest due;
    (2) Gas supply realignment (GSR) costs. The GSR costs result from a 
pipeline reforming or terminating supply contracts with producers to 
implement the restructuring requirements of FERC Orders in 18 CFR part 
284;
    (3) Commodity charges. The commodity charge allows the pipeline to 
recover the costs of providing service;
    (4) Wheeling costs. Hub operators charge a wheeling cost for 
transporting gas from one pipeline to either the same or another 
pipeline through a market center or hub. A hub is a connected manifold 
of pipelines through which a series of incoming pipelines are 
interconnected to a series of outgoing pipelines;
    (5) Gas Research Institute (GRI) fees. The GRI conducts research, 
development, and commercialization programs on natural gas related 
topics for the benefit of the U.S. gas industry and gas customers. GRI 
fees are allowable provided such fees are mandatory in FERC-approved 
tariffs;
    (6) Annual Charge Adjustment (ACA) fees. FERC charges these fees to 
pipelines to pay for its operating expenses;
    (7) Payments (either volumetric or in value) for actual or 
theoretical losses. However, theoretical losses are not deductible in 
non-arm's-length transportation arrangements unless the transportation 
allowance is based on arm's-length transportation rates charged under a 
FERC- or State regulatory-approved tariff under paragraph (b)(5) of 
this section. If you receive volumes or credit for line gain, you must 
reduce your transportation allowance accordingly and pay any resulting 
royalties and late payment interest due;
    (8) Temporary storage services. This includes short duration 
storage services offered by market centers or hubs (commonly referred 
to as ``parking'' or ``banking''), or other temporary storage services 
provided by pipeline transporters, whether actual or provided as a 
matter of accounting. Temporary storage is limited to 30 days or less; 
and
    (9) Supplemental costs for compression, dehydration, and treatment 
of gas. ONRR allows these costs only if such services are required for 
transportation and exceed the services necessary to place production 
into marketable condition required under Sec. Sec.  1206.152(i) and 
1206.153(i) of this part.
    (10) Costs of surety. You may deduct the costs of securing a letter 
of credit, or other surety, that the pipeline requires you as a shipper 
to maintain under an arm's-length transportation contract.
    (g) Nonallowable costs in determining transportation allowances. 
Lessees may not include the following costs in determining the arm's-
length transportation allowance under paragraph (a) of this section or 
the non-arm's-length transportation allowance under paragraph (b) of 
this section:
    (1) Fees or costs incurred for storage. This includes storing 
production in a storage facility, whether on or off the lease, for more 
than 30 days;
    (2) Aggregator/marketer fees. This includes fees you pay to another 
person (including your affiliates) to market your gas, including 
purchasing and reselling the gas, or finding or maintaining a market 
for the gas production;
    (3) Penalties you incur as shipper. These penalties include, but 
are not limited to:
    (i) Over-delivery cash-out penalties. This includes the difference 
between the price the pipeline pays you for over-delivered volumes 
outside the tolerances and the price you receive for over-delivered 
volumes within the tolerances;
    (ii) Scheduling penalties. This includes penalties you incur for 
differences between daily volumes delivered into the pipeline and 
volumes scheduled or nominated at a receipt or delivery point;
    (iii) Imbalance penalties. This includes penalties you incur 
(generally on a monthly basis) for differences between volumes 
delivered into the pipeline and volumes scheduled or nominated at a 
receipt or delivery point; and
    (iv) Operational penalties. This includes fees you incur for 
violation of the pipeline's curtailment or operational orders issued to 
protect the operational integrity of the pipeline;
    (4) Intra-hub transfer fees. These are fees you pay to hub 
operators for administrative services (e.g., title transfer tracking) 
necessary to account for the sale of gas within a hub;
    (5) Fees paid to brokers. This includes fees paid to parties who 
arrange marketing or transportation, if such fees are separately 
identified from aggregator/marketer fees;
    (6) Fees paid to scheduling service providers. This includes fees 
paid to parties who provide scheduling services, if such fees are 
separately identified from aggregator/marketer fees;
    (7) Internal costs. This includes salaries and related costs, rent/
space costs, office equipment costs, legal fees, and other costs to 
schedule, nominate, and account for sale or movement of production; and
    (8) Other nonallowable costs. Any cost you incur for services you 
are required to provide at no cost to the lessor.
    (h) Other transportation cost determinations. Use this section when 
calculating transportation costs to establish value using a netback 
procedure or any other procedure that requires deduction of 
transportation costs.


Sec.  [thinsp]1206.158   Processing allowances--general.

    (a) Where the value of gas is determined pursuant to Sec.  
[thinsp]1206.153 of this subpart, a deduction shall be allowed for the 
reasonable actual costs of processing.
    (b) Processing costs must be allocated among the gas plant 
products. A separate processing allowance must be determined for each 
gas plant product

[[Page 36973]]

and processing plant relationship. Natural gas liquids (NGL's) shall be 
considered as one product.
    (c)(1) Except as provided in paragraph (d)(2) of this section, the 
processing allowance shall not be applied against the value of the 
residue gas. Where there is no residue gas ONRR may designate an 
appropriate gas plant product against which no allowance may be 
applied.
    (2) Except as provided in paragraph (c)(3) of this section, the 
processing allowance deduction on the basis of an individual product 
shall not exceed 66 \2/3\ percent of the value of each gas plant 
product determined in accordance with Sec.  [thinsp]1206.153 of this 
subpart (such value to be reduced first for any transportation 
allowances related to postprocessing transportation authorized by Sec.  
[thinsp]1206.156 of this subpart).
    (3) Upon request of a lessee, ONRR may approve a processing 
allowance in excess of the limitation prescribed by paragraph (c)(2) of 
this section. The lessee must demonstrate that the processing costs 
incurred in excess of the limitation prescribed in paragraph (c)(2) of 
this section were reasonable, actual, and necessary. An application for 
exception (using form ONRR-4393, Request to Exceed Regulatory Allowance 
Limitation) shall contain all relevant and supporting documentation for 
ONRR to make a determination. Under no circumstances shall the value 
for royalty purposes of any gas plant product be reduced to zero.
    (d)(1) Except as provided in paragraph (d)(2) of this section, no 
processing cost deduction shall be allowed for the costs of placing 
lease products in marketable condition, including dehydration, 
separation, compression, or storage, even if those functions are 
performed off the lease or at a processing plant. Where gas is 
processed for the removal of acid gases, commonly referred to as 
``sweetening,'' no processing cost deduction shall be allowed for such 
costs unless the acid gases removed are further processed into a gas 
plant product. In such event, the lessee shall be eligible for a 
processing allowance as determined in accordance with this subpart. 
However, ONRR will not grant any processing allowance for processing 
lease production which is not royalty bearing.
    (2)(i) If the lessee incurs extraordinary costs for processing gas 
production from a gas production operation, it may apply to ONRR for an 
allowance for those costs which shall be in addition to any other 
processing allowance to which the lessee is entitled pursuant to this 
section. Such an allowance may be granted only if the lessee can 
demonstrate that the costs are, by reference to standard industry 
conditions and practice, extraordinary, unusual, or unconventional.
    (ii) Prior ONRR approval to continue an extraordinary processing 
cost allowance is not required. However, to retain the authority to 
deduct the allowance the lessee must report the deduction to ONRR in a 
form and manner prescribed by ONRR.
    (e) If ONRR determines that a lessee has improperly determined a 
processing allowance authorized by this subpart, then the lessee must 
pay any additional royalties, plus interest determined under Sec.  
[thinsp]1218.54 of this chapter, or will be entitled to a credit with 
interest. If the lessee takes a deduction for processing on form ONRR-
2014 by improperly netting the allowance against the sales value of the 
gas plant products instead of reporting the allowance as a separate 
entry, ONRR may assess a civil penalty under 30 CFR part 1241.


Sec.  [thinsp]1206.159  Determination of processing allowances.

    (a) Arm's-length processing contracts. (1)(i) For processing costs 
incurred by a lessee under an arm's-length contract, the processing 
allowance shall be the reasonable actual costs incurred by the lessee 
for processing the gas under that contract, except as provided in 
paragraphs (a)(1)(ii) and (iii) of this section, subject to monitoring, 
review, audit, and adjustment. The lessee shall have the burden of 
demonstrating that its contract is arm's-length. ONRR's prior approval 
is not required before a lessee may deduct costs incurred under an 
arm's-length contract. The lessee must claim a processing allowance by 
reporting it as a separate entry on the form ONRR-2014.
    (ii) In conducting reviews and audits, ONRR will examine whether 
the contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the processor for the 
processing. If the contract reflects more than the total consideration, 
then the ONRR may require that the processing allowance be determined 
in accordance with paragraph (b) of this section.
    (iii) If ONRR determines that the consideration paid pursuant to an 
arm's-length processing contract does not reflect the reasonable value 
of the processing because of misconduct by or between the contracting 
parties, or because the lessee otherwise has breached its duty to the 
lessor to market the production for the mutual benefit of the lessee 
and lessor, then ONRR shall require that the processing allowance be 
determined in accordance with paragraph (b) of this section. When ONRR 
determines that the value of the processing may be unreasonable, ONRR 
will notify the lessee and give the lessee an opportunity to provide 
written information justifying the lessee's processing costs.
    (2) If an arm's-length processing contract includes more than one 
gas plant product and the processing costs attributable to each product 
can be determined from the contract, then the processing costs for each 
gas plant product shall be determined in accordance with the contract. 
No allowance may be taken for the costs of processing lease production 
which is not royalty-bearing.
    (3) If an arm's-length processing contract includes more than one 
gas plant product and the processing costs attributable to each product 
cannot be determined from the contract, the lessee shall propose an 
allocation procedure to ONRR. The lessee may use its proposed 
allocation procedure until ONRR issues its determination. The lessee 
shall submit all relevant data to support its proposal. ONRR shall then 
determine the processing allowance based upon the lessee's proposal and 
any additional information ONRR deems necessary. No processing 
allowance will be granted for the costs of processing lease production 
which is not royalty bearing. The lessee must submit the allocation 
proposal within 3 months of claiming the allocated deduction on form 
ONRR-2014.
    (4) Where the lessee's payments for processing under an arm's-
length contract are not based on a dollar per unit basis, the lessee 
shall convert whatever consideration is paid to a dollar value 
equivalent for the purposes of this section.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length processing contract or has no contract, including those 
situations where the lessee performs processing for itself, the 
processing allowance will be based upon the lessee's reasonable actual 
costs as provided in this paragraph. All processing allowances deducted 
under a non-arm's-length or no-contract situation are subject to 
monitoring, review, audit, and adjustment. The lessee must claim a 
processing allowance by reflecting it as a separate entry on the form 
ONRR-2014. When necessary or appropriate, ONRR may direct a lessee to 
modify its estimated or actual processing allowance.
    (2) The processing allowance for non-arm's-length or no-contract 
situations shall be based upon the lessee's actual costs for processing 
during the reporting

[[Page 36974]]

period, including operating and maintenance expenses, overhead, and 
either depreciation and a return on undepreciated capital investment in 
accordance with paragraph (b)(2)(iv)(A) of this section, or a cost 
equal to the initial depreciable investment in the processing plant 
multiplied by a rate of return in accordance with paragraph 
(b)(2)(iv)(B) of this section. Allowable capital costs are generally 
those costs for depreciable fixed assets (including costs of delivery 
and installation of capital equipment) which are an integral part of 
the processing plant.
    (i) Allowable operating expenses include: Operations supervision 
and engineering; operations labor; fuel; utilities; materials; ad 
valorem property taxes; rent; supplies; and any other directly 
allocable and attributable operating expense which the lessee can 
document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
processing plant; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which 
the lessee can document.
    (iii) Overhead directly attributable and allocable to the operation 
and maintenance of the processing plant is an allowable expense. State 
and Federal income taxes and severance taxes, including royalties, are 
not allowable expenses.
    (iv) A lessee may use either depreciation or a return on 
depreciable capital investment. When a lessee has elected to use either 
method for a processing plant, the lessee may not later elect to change 
to the other alternative without approval of the ONRR.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the processing plant services, or a 
unit-of-production method. After an election is made, the lessee may 
not change methods without ONRR approval. A change in ownership of a 
processing plant shall not alter the depreciation schedule established 
by the original processor/lessee for purposes of the allowance 
calculation. With or without a change in ownership, a processing plant 
shall be depreciated only once. Equipment shall not be depreciated 
below a reasonable salvage value.
    (B) The ONRR shall allow as a cost an amount equal to the allowable 
initial capital investment in the processing plant multiplied by the 
rate of return determined pursuant to paragraph (b)(2)(v) of this 
section. No allowance shall be provided for depreciation. This 
alternative shall apply only to plants first placed in service after 
March 1, 1988.
    (v) The rate of return must be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return must be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) The processing allowance for each gas plant product shall be 
determined based on the lessee's reasonable and actual cost of 
processing the gas. Allocation of costs to each gas plant product shall 
be based upon generally accepted accounting principles. The lessee may 
not take an allowance for the costs of processing lease production 
which is not royalty bearing.
    (4) A lessee may apply to ONRR for an exception from the 
requirement that it compute actual costs in accordance with paragraphs 
(b)(1) through (b)(3) of this section. The ONRR may grant the exception 
only if: (i) The lessee has arm's-length contracts for processing other 
gas production at the same processing plant; and (ii) at least 50 
percent of the gas processed annually at the plant is processed 
pursuant to arm's-length processing contracts; if the ONRR grants the 
exception, the lessee shall use as its processing allowance the volume 
weighted average prices charged other persons pursuant to arm's-length 
contracts for processing at the same plant.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify ONRR of an allowance based on incurred costs by 
using a separate entry on the form ONRR-2014.
    (ii) ONRR may require that a lessee submit arm's-length processing 
contracts and related documents. Documents shall be submitted within a 
reasonable time, as determined by ONRR.
    (2) Non-arm's-length or no contract. (i) The lessee must notify 
ONRR of an allowance based on the incurred costs by using a separate 
entry on the form ONRR-2014.
    (ii) For new processing plants, the lessee's initial deduction 
shall include estimates of the allowable gas processing costs for the 
applicable period. Cost estimates shall be based upon the most recently 
available operations data for the plant or, if such data are not 
available, the lessee shall use estimates based upon industry data for 
similar gas processing plants.
    (iii) Upon request by ONRR, the lessee shall submit all data used 
to prepare the allowance deduction. The data shall be provided within a 
reasonable period of time, as determined by ONRR.
    (iv) If the lessee is authorized to use the volume weighted average 
prices charged other persons as its processing allowance in accordance 
with paragraph (b)(4) of this section, it shall follow the reporting 
requirements of paragraph (c)(1) of this section.
    (d) Interest. (1) If a lessee deducts a processing allowance on its 
form ONRR-2014 that exceeds 66 \2/3\ percent of the value of the gas 
processed without obtaining prior approval of ONRR under Sec.  
1206.158, the lessee shall pay interest on the excess allowance amount 
taken from the date such amount is taken to the date the lessee files 
an exception request with ONRR.
    (2) If a lessee erroneously reports a processing allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be 
determined in accordance with Sec.  1218.54 of this chapter.
    (e) Adjustments. (1) If the actual processing allowance is less 
than the amount the lessee has taken on form ONRR-2014 for each month 
during the allowance reporting period, the lessee shall pay additional 
royalties due plus interest computed under Sec.  [thinsp]1218.54 of 
this chapter from the allowance reporting period when the lessee took 
the deduction to the date the lessee repays the difference to ONRR. If 
the actual processing allowance is greater than the amount the lessee 
has taken on form ONRR-2014 for each month during the allowance 
reporting period, the lessee shall be entitled to a credit with 
interest.
    (2) For lessees processing production from onshore Federal leases, 
the lessee must submit a corrected form ONRR-2014 to reflect actual 
costs, together with any payment, in accordance with instructions 
provided by ONRR.
    (3) For lessees processing gas production from leases on the OCS, 
if the lessee's estimated processing allowance exceeds the allowance 
based on actual costs, the lessee must submit a corrected form ONRR-
2014 to reflect actual costs, together with its payment, in accordance 
with instructions provided by ONRR. If the lessee's estimated costs 
were less than the actual costs, the refund procedure will be specified 
by ONRR.
    (f) Other processing cost determinations. The provisions of this 
section shall apply to determine processing costs when establishing 
value using a net back valuation

[[Page 36975]]

procedure or any other procedure that requires deduction of processing 
costs.


Sec.  [thinsp]1206.160  Operating allowances.

    Notwithstanding any other provisions in these regulations, an 
operating allowance may be used for the purpose of computing payment 
obligations when specified in the notice of sale and the lease. The 
allowance amount or formula shall be specified in the notice of sale 
and in the lease agreement.

0
8. Revise subpart F to read as follows:
Subpart F--Federal Coal
Sec.
1206.250 Purpose and scope.
1206.251 Definitions.
1206.252 Information collection.
1206.253 Coal subject to royalties--general provisions.
1206.254 Quality and quantity measurement standards for reporting 
and paying royalties.
1206.255 Point of royalty determination.
1206.256 Valuation standards for cents-per-ton leases.
1206.257 Valuation standards for ad valorem leases.
1206.258 Washing allowances--general.
1206.259 Determination of washing allowances.
1206.260 Allocation of washed coal.
1206.261 Transportation allowances--general.
1206.262 Determination of transportation allowances.
1206.263 [Reserved]
1206.264 In-situ and surface gasification and liquefaction 
operations.
1206.265 Value enhancement of marketable coal.

Subpart F--Federal Coal


Sec.  [thinsp]1206.250  Purpose and scope.

    (a) This subpart is applicable to all coal produced from Federal 
coal leases. The purpose of this subpart is to establish the value of 
coal produced for royalty purposes, of all coal from Federal leases 
consistent with the mineral leasing laws, other applicable laws and 
lease terms.
    (b) If the specific provisions of any statute or settlement 
agreement between the United States and a lessee resulting from 
administrative or judicial litigation, or any coal lease subject to the 
requirements of this subpart, are inconsistent with any regulation in 
this subpart then the statute, lease provision, or settlement shall 
govern to the extent of that inconsistency.
    (c) All royalty payments made to the Office of Natural Resources 
Revenue (ONRR) are subject to later audit and adjustment.


Sec.  [thinsp]1206.251  Definitions.

    Ad valorem lease means a lease where the royalty due to the lessor 
is based upon a percentage of the amount or value of the coal.
    Allowance means a deduction used in determining value for royalty 
purposes. Coal washing allowance means an allowance for the reasonable, 
actual costs incurred by the lessee for coal washing. Transportation 
allowance means an allowance for the reasonable, actual costs incurred 
by the lessee for moving coal to a point of sale or point of delivery 
remote from both the lease and mine or wash plant.
    Area means a geographic region in which coal has similar quality 
and economic characteristics. Area boundaries are not officially 
designated and the areas are not necessarily named.
    Arm's-length contract means a contract or agreement that has been 
arrived at in the marketplace between independent, nonaffiliated 
persons with opposing economic interests regarding that contract. For 
purposes of this subpart, two persons are affiliated if one person 
controls, is controlled by, or is under common control with another 
person. For purposes of this subpart, based on the instruments of 
ownership of the voting securities of an entity, or based on other 
forms of ownership:
    (a) Ownership in excess of 50 percent constitutes control;
    (b) Ownership of 10 through 50 percent creates a presumption of 
control; and
    (c) Ownership of less than 10 percent creates a presumption of 
noncontrol which ONRR may rebut if it demonstrates actual or legal 
control, including the existence of interlocking directorates.
    Notwithstanding any other provisions of this subpart, contracts 
between relatives, either by blood or by marriage, are not arm's-length 
contracts. The ONRR may require the lessee to certify ownership 
control. To be considered arm's-length for any production month, a 
contract must meet the requirements of this definition for that 
production month as well as when the contract was executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty payment 
compliance activities of lessees or other interest holders who pay 
royalties, rents, or bonuses on Federal leases.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Coal means coal of all ranks from lignite through anthracite.
    Coal washing means any treatment to remove impurities from coal. 
Coal washing may include, but is not limited to, operations such as 
flotation, air, water, or heavy media separation; drying; and related 
handling (or combination thereof).
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by 
law that with due consideration creates an obligation.
    Gross proceeds (for royalty payment purposes) means the total 
monies and other consideration accruing to a coal lessee for the 
production and disposition of the coal produced. Gross proceeds 
includes, but is not limited to, payments to the lessee for certain 
services such as crushing, sizing, screening, storing, mixing, loading, 
treatment with substances including chemicals or oils, and other 
preparation of the coal to the extent that the lessee is obligated to 
perform them at no cost to the Federal Government. Gross proceeds, as 
applied to coal, also includes but is not limited to reimbursements for 
royalties, taxes or fees, and other reimbursements. Tax reimbursements 
are part of the gross proceeds accruing to a lessee even though the 
Federal royalty interest may be exempt from taxation. Monies and other 
consideration, including the forms of consideration identified in this 
paragraph, to which a lessee is contractually or legally entitled but 
which it does not seek to collect through reasonable efforts are also 
part of gross proceeds.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States for a 
Federal coal resource under a mineral leasing law that authorizes 
exploration for, development or extraction of, or removal of coal--or 
the land covered by that authorization, whichever is required by the 
context.
    Lessee means any person to whom the United States issues a lease, 
and any person who has been assigned an obligation to make royalty or 
other payments required by the lease. This includes any person who has 
an interest in a lease as well as an operator or payor who has no 
interest in the lease but who has assumed the royalty payment 
responsibility.
    Like-quality coal means coal that has similar chemical and physical 
characteristics.
    Marketable condition means coal that is sufficiently free from 
impurities and otherwise in a condition that it will be accepted by a 
purchaser under a sales contract typical for that area.
    Mine means an underground or surface excavation or series of 
excavations and the surface or underground support facilities that

[[Page 36976]]

contribute directly or indirectly to mining, production, preparation, 
and handling of lease products.
    Net-back method means a method for calculating market value of coal 
at the lease or mine. Under this method, costs of transportation, 
washing, handling, etc., are deducted from the ultimate proceeds 
received for the coal at the first point at which reasonable values for 
the coal may be determined by a sale pursuant to an arm's-length 
contract or by comparison to other sales of coal, to ascertain value at 
the mine.
    Net output means the quantity of washed coal that a washing plant 
produces.
    Netting is the deduction of an allowance from the sales value by 
reporting a one line net sales value, instead of correctly reporting 
the deduction as a separate line item on the form ONRR-4430.
    Person means by individual, firm, corporation, association, 
partnership, consortium, or joint venture.
    Sales type code means the contract type or general disposition 
(e.g., arm's-length or non-arm's-length) of production from the lease. 
The sales type code applies to the sales contract, or other 
disposition, and not to the arm's-length or non-arm's-length nature of 
a transportation or washing allowance.
    Spot market price means the price received under any sales 
transaction when planned or actual deliveries span a short period of 
time, usually not exceeding one year.


Sec.  [thinsp]1206.252  Information collection.

    The information collection requirements contained in this subpart 
have been approved by the Office of Management and Budget (OMB) under 
44 U.S.C. 3501 et seq. The forms, filing date, and approved OMB control 
numbers are identified in part 1210--Forms and Reports.


Sec.  [thinsp]1206.253  Coal subject to royalties--general provisions.

    (a) All coal (except coal unavoidably lost as determined by BLM 
under 43 CFR part 3400) from a Federal lease subject to this part is 
subject to royalty. This includes coal used, sold, or otherwise 
disposed of by the lessee on or off the lease.
    (b) If a lessee receives compensation for unavoidably lost coal 
through insurance coverage or other arrangements, royalties at the rate 
specified in the lease are to be paid on the amount of compensation 
received for the coal. No royalty is due on insurance compensation 
received by the lessee for other losses.
    (c) If waste piles or slurry ponds are reworked to recover coal, 
the lessee shall pay royalty at the rate specified in the lease at the 
time the recovered coal is used, sold, or otherwise finally disposed 
of. The royalty rate shall be that rate applicable to the production 
method used to initially mine coal in the waste pile or slurry pond; 
i.e., underground mining method or surface mining method. Coal in waste 
pits or slurry ponds initially mined from Federal leases shall be 
allocated to such leases regardless of whether it is stored on Federal 
lands. The lessee shall maintain accurate records to determine to which 
individual Federal lease coal in the waste pit or slurry pond should be 
allocated. However, nothing in this section requires payment of a 
royalty on coal for which a royalty has already been paid.


Sec.  [thinsp]1206.254  Quality and quantity measurement standards for 
reporting and paying royalties.

    For all leases subject to this subpart, the quantity of coal on 
which royalty is due shall be measured in short tons (of 2,000 pounds 
each) by methods prescribed by the BLM. Coal quantity information will 
be reported on appropriate forms required under 30 CFR part 1210--Forms 
and Reports.


Sec.  [thinsp]1206.255  Point of royalty determination.

    (a) For all leases subject to this subpart, royalty shall be 
computed on the basis of the quantity and quality of Federal coal in 
marketable condition measured at the point of royalty measurement as 
determined jointly by BLM and ONRR.
    (b) Coal produced and added to stockpiles or inventory does not 
require payment of royalty until such coal is later used, sold, or 
otherwise finally disposed of. ONRR may ask BLM to increase the lease 
bond to protect the lessor's interest when BLM determines that 
stockpiles or inventory become excessive so as to increase the risk of 
degradation of the resource.
    (c) The lessee shall pay royalty at a rate specified in the lease 
at the time the coal is used, sold, or otherwise finally disposed of, 
unless otherwise provided for at Sec.  [thinsp]1206.256(d) of this 
subpart.


Sec.  [thinsp]1206.256  Valuation standards for cents-per-ton leases.

    (a) This section is applicable to coal leases on Federal lands 
which provide for the determination of royalty on a cents-per-ton (or 
other quantity) basis.
    (b) The royalty for coal from leases subject to this section shall 
be based on the dollar rate per ton prescribed in the lease. That 
dollar rate shall be applicable to the actual quantity of coal used, 
sold, or otherwise finally disposed of, including coal which is 
avoidably lost as determine by BLM pursuant to 43 CFR part 3400.
    (c) For leases subject to this section, there shall be no 
allowances for transportation, removal of impurities, coal washing, or 
any other processing or preparation of the coal.
    (d) When a coal lease is readjusted pursuant to 43 CFR part 3400 
and the royalty valuation method changes from a cents-per-ton basis to 
an ad valorem basis, coal which is produced prior to the effective date 
of readjustment and sold or used within 30 days of the effective date 
of readjustment shall be valued pursuant to this section. All coal that 
is not used, sold, or otherwise finally disposed of within 30 days 
after the effective date of readjustment shall be valued pursuant to 
the provisions of Sec.  [thinsp]1206.257 of this subpart, and royalties 
shall be paid at the royalty rate specified in the readjusted lease.


Sec.  [thinsp]1206.257  Valuation standards for ad valorem leases.

    (a) This section is applicable to coal leases on Federal lands 
which provide for the determination of royalty as a percentage of the 
amount of value of coal (ad valorem). The value for royalty purposes of 
coal from such leases shall be the value of coal determined under this 
section, less applicable coal washing allowances and transportation 
allowances determined under Sec. Sec.  [thinsp]1206.258 through 
1206.262 of this subpart, or any allowance authorized by Sec.  
[thinsp]1206.265 of this subpart. The royalty due shall be equal to the 
value for royalty purposes multiplied by the royalty rate in the lease.
    (b)(1) The value of coal that is sold pursuant to an arm's-length 
contract shall be the gross proceeds accruing to the lessee, except as 
provided in paragraphs (b)(2), (3), and (5) of this section. The lessee 
shall have the burden of demonstrating that its contract is arm's-
length. The value which the lessee reports, for royalty purposes, is 
subject to monitoring, review, and audit.
    (2) In conducting reviews and audits, ONRR will examine whether the 
contract reflects the total consideration actually transferred either 
directly or indirectly from the buyer to the seller for the coal 
produced. If the contract does not reflect the total consideration, 
then the ONRR may require that the coal sold pursuant to that contract 
be valued in accordance with paragraph (c) of this section. Value may 
not be based on less than the gross proceeds accruing to the lessee for 
the coal production, including the additional consideration.

[[Page 36977]]

    (3) If ONRR determines that the gross proceeds accruing to the 
lessee pursuant to an arm's-length contract do not reflect the 
reasonable value of the production because of misconduct by or between 
the contracting parties, or because the lessee otherwise has breached 
its duty to the lessor to market the production for the mutual benefit 
of the lessee and the lessor, then ONRR shall require that the coal 
production be valued pursuant to paragraph (c)(2)(ii), (iii), (iv), or 
(v) of this section, and in accordance with the notification 
requirements of paragraph (d)(3) of this section. When ONRR determines 
that the value may be unreasonable, ONRR will notify the lessee and 
give the lessee an opportunity to provide written information 
justifying the lessee's reported coal value.
    (4) ONRR may require a lessee to certify that its arm's-length 
contract provisions include all of the consideration to be paid by the 
buyer, either directly or indirectly, for the coal production.
    (5) The value of production for royalty purposes shall not include 
payments received by the lessee pursuant to a contract which the lessee 
demonstrates, to ONRR's satisfaction, were not part of the total 
consideration paid for the purchase of coal production.
    (c)(1) The value of coal from leases subject to this section and 
which is not sold pursuant to an arm's-length contract shall be 
determined in accordance with this section.
    (2) If the value of the coal cannot be determined pursuant to 
paragraph (b) of this section, then the value shall be determined 
through application of other valuation criteria. The criteria shall be 
considered in the following order, and the value shall be based upon 
the first applicable criterion:
    (i) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition of produced 
coal by other than an arm's-length contract), provided that those gross 
proceeds are within the range of the gross proceeds derived from, or 
paid under, comparable arm's-length contracts between buyers and 
sellers neither of whom is affiliated with the lessee for sales, 
purchases, or other dispositions of like-quality coal produced in the 
area. In evaluating the comparability of arm's-length contracts for the 
purposes of these regulations, the following factors shall be 
considered: Price, time of execution, duration, market or markets 
served, terms, quality of coal, quantity, and such other factors as may 
be appropriate to reflect the value of the coal;
    (ii) Prices reported for that coal to a public utility commission;
    (iii) Prices reported for that coal to the Energy Information 
Administration of the Department of Energy;
    (iv) Other relevant matters including, but not limited to, 
published or publicly available spot market prices, or information 
submitted by the lessee concerning circumstances unique to a particular 
lease operation or the saleability of certain types of coal;
    (v) If a reasonable value cannot be determined using paragraphs 
(c)(2) (i), (ii), (iii), or (iv) of this section, then a net-back 
method or any other reasonable method shall be used to determine value.
    (3) When the value of coal is determined pursuant to paragraph 
(c)(2) of this section, that value determination shall be consistent 
with the provisions contained in paragraph (b)(5) of this section.
    (d)(1) Where the value is determined pursuant to paragraph (c) of 
this section, that value does not require ONRR's prior approval. 
However, the lessee shall retain all data relevant to the determination 
of royalty value. Such data shall be subject to review and audit, and 
ONRR will direct a lessee to use a different value if it determines 
that the reported value is inconsistent with the requirements of these 
regulations.
    (2) Any Federal lessee will make available upon request to the 
authorized ONRR or State representatives, to the Inspector General of 
the Department of the Interior or other persons authorized to receive 
such information, arm's-length sales value and sales quantity data for 
like-quality coal sold, purchased, or otherwise obtained by the lessee 
from the area.
    (3) A lessee shall notify ONRR if it has determined value pursuant 
to paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section. The 
notification shall be by letter to the Director for Office of Natural 
Resources Revenue of his/her designee. The letter shall identify the 
valuation method to be used and contain a brief description of the 
procedure to be followed. The notification required by this section is 
a one-time notification due no later than the month the lessee first 
reports royalties on the form ONRR-4430 using a valuation method 
authorized by paragraphs (c)(2)(ii), (iii), (iv), or (v) of this 
section, and each time there is a change in a method under paragraphs 
(c)(2)(iv) or (v) of this section.
    (e) If ONRR determines that a lessee has not properly determined 
value, the lessee shall be liable for the difference, if any, between 
royalty payments made based upon the value it has used and the royalty 
payments that are due based upon the value established by ONRR. The 
lessee shall also be liable for interest computed pursuant to Sec.  
[thinsp]1218.202 of this chapter. If the lessee is entitled to a 
credit, ONRR will provide instructions for the taking of that credit.
    (f) The lessee may request a value determination from ONRR. In that 
event, the lessee shall propose to ONRR a value determination method, 
and may use that method in determining value for royalty purposes until 
ONRR issues its decision. The lessee shall submit all available data 
relevant to its proposal. The ONRR shall expeditiously determine the 
value based upon the lessee's proposal and any additional information 
ONRR deems necessary. That determination shall remain effective for the 
period stated therein. After ONRR issues its determination, the lessee 
shall make the adjustments in accordance with paragraph (e) of this 
section.
    (g) Notwithstanding any other provisions of this section, under no 
circumstances shall the value for royalty purposes be less than the 
gross proceeds accruing to the lessee for the disposition of produced 
coal less applicable provisions of paragraph (b)(5) of this section and 
less applicable allowances determined pursuant to Sec. Sec.  
[thinsp]1206.258 through 1206.262 and 1206.265 of this subpart.
    (h) The lessee is required to place coal in marketable condition at 
no cost to the Federal Government. Where the value established under 
this section is determined by a lessee's gross proceeds, that value 
shall be increased to the extent that the gross proceeds has been 
reduced because the purchaser, or any other person, is providing 
certain services, the cost of which ordinarily is the responsibility of 
the lessee to place the coal in marketable condition.
    (i) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims under its contract. Absent 
contract revision or amendment, if the lessee fails to take proper or 
timely action to receive prices or benefits to which it is entitled, it 
must pay royalty at a value based upon that obtainable price or 
benefit. Contract revisions or amendments shall be in writing and 
signed by all parties to an arm's-length contract, and may be 
retroactively applied to value for royalty purposes for a period not to 
exceed two years, unless ONRR approves a longer period. If the lessee 
makes timely application for a price increase allowed under its 
contract but the purchaser refuses, and the lessee takes reasonable 
measures,

[[Page 36978]]

which are documented, to force purchaser compliance, the lessee will 
owe no additional royalties unless or until monies or consideration 
resulting from the price increase are received. This paragraph shall 
not be construed to permit a lessee to avoid its royalty payment 
obligation in situations where a purchaser fails to pay, in whole or in 
part or timely, for a quantity of coal.
    (j) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or other like process 
that results in a redetermination by ONRR of value under this section 
shall be considered final or binding as against the Federal Government 
or its beneficiaries until the audit period is formally closed.
    (k) Certain information submitted to ONRR to support valuation 
proposals, including transportation, coal washing, or other allowances 
under Sec.  [thinsp]1206.265 of this subpart, is exempted from 
disclosure by the Freedom of Information Act, 5 U.S.C. 522. Any data 
specified by the Act to be privileged, confidential, or otherwise 
exempt shall be maintained in a confidential manner in accordance with 
applicable law and regulations. All requests for information about 
determinations made under this part are to be submitted in accordance 
with the Freedom of Information Act regulation of the Department of the 
Interior, 43 CFR part 2.


Sec.  [thinsp]1206.258  Washing allowances--general.

    (a) For ad valorem leases subject to Sec.  [thinsp]1206.257 of this 
subpart, ONRR shall, as authorized by this section, allow a deduction 
in determining value for royalty purposes for the reasonable, actual 
costs incurred to wash coal, unless the value determined pursuant to 
Sec.  [thinsp]1206.257 of this subpart was based upon like-quality 
unwashed coal. Under no circumstances will the authorized washing 
allowance and the transportation allowance reduce the value for royalty 
purposes to zero.
    (b) If ONRR determines that a lessee has improperly determined a 
washing allowance authorized by this section, then the lessee shall be 
liable for any additional royalties, plus interest determined in 
accordance with Sec.  [thinsp]1218.202 of this chapter, or shall be 
entitled to a credit without interest.
    (c) Lessees shall not disproportionately allocate washing costs to 
Federal leases.
    (d) No cost normally associated with mining operations and which 
are necessary for placing coal in marketable condition shall be allowed 
as a cost of washing.
    (e) Coal washing costs shall only be recognized as allowances when 
the washed coal is sold and royalties are reported and paid.


Sec.  [thinsp]1206.259  Determination of washing allowances.

    (a) Arm's-length contracts. (1) For washing costs incurred by a 
lessee under an arm's-length contract, the washing allowance shall be 
the reasonable actual costs incurred by the lessee for washing the coal 
under that contract, subject to monitoring, review, audit, and possible 
future adjustment. The lessee shall have the burden of demonstrating 
that its contract is arm's-length. ONRR's prior approval is not 
required before a lessee may deduct costs incurred under an arm's-
length contract. The lessee must claim a washing allowance by reporting 
it as a separate line entry on the form ONRR-4430.
    (2) In conducting reviews and audits, ONRR will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the washer for the 
washing. If the contract reflects more than the total consideration 
paid, then the ONRR may require that the washing allowance be 
determined in accordance with paragraph (b) of this section.
    (3) If ONRR determines that the consideration paid pursuant to an 
arm's-length washing contract does not reflect the reasonable value of 
the washing because of misconduct by or between the contracting 
parties, or because the lessee otherwise has breached its duty to the 
lessor to market the production for the mutual benefit of the lessee 
and the lessor, then ONRR shall require that the washing allowance be 
determined in accordance with paragraph (b) of this section. When ONRR 
determines that the value of the washing may be unreasonable, ONRR will 
notify the lessee and give the lessee an opportunity to provide written 
information justifying the lessee's washing costs.
    (4) Where the lessee's payments for washing under an arm's-length 
contract are not based on a dollar-per-unit basis, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent. 
Washing allowances shall be expressed as a cost per ton of coal washed.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs washing for itself, the washing allowance 
will be based upon the lessee's reasonable actual costs. All washing 
allowances deducted under a non-arm's-length or no contract situation 
are subject to monitoring, review, audit, and possible future 
adjustment. The lessee must claim a washing allowance by reporting it 
as a separate line entry on the form ONRR-4430. When necessary or 
appropriate, ONRR may direct a lessee to modify its estimated or actual 
washing allowance.
    (2) The washing allowance for non-arm's-length or no contract 
situations shall be based upon the lessee's actual costs for washing 
during the reported period, including operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv) (A) of this section, or a cost equal to the depreciable 
investment in the wash plant multiplied by the rate of return in 
accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the wash plant.
    (i) Allowable operating expenses include: Operations supervision 
and engineering; operations labor; fuel; utilities; materials; ad 
valorem property taxes, rent; supplies; and any other directly 
allocable and attributable operating expense which the lessee can 
document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
wash plant; maintenance of equipment; maintenance labor; and other 
directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the wash plant is an allowable expense. State and 
Federal income taxes and severance taxes, including royalties, are not 
allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this 
section. After a lessee has elected to use either method for a wash 
plant, the lessee may not later elect to change to the other 
alternative without approval of the ONRR.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the wash plant services, whichever is 
appropriate, or a unit of production method. After an election is made, 
the lessee may not change methods without ONRR approval. A change in 
ownership of a wash plant shall not alter the depreciation schedule 
established by the original operator/lessee for purposes of the 
allowance calculation. With or without a change in

[[Page 36979]]

ownership, a wash plant shall be depreciated only once. Equipment shall 
not be depreciated below a reasonable salvage value.
    (B) ONRR shall allow as a cost an amount equal to the allowable 
capital investment in the wash plant multiplied by the rate of return 
determined pursuant to paragraph (b)(2)(v) of this section. No 
allowance shall be provided for depreciation. This alternative shall 
apply only to plants first placed in service or acquired after March 1, 
1989.
    (v) The rate of return must be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return must be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) The washing allowance for coal shall be determined based on the 
lessee's reasonable and actual cost of washing the coal. The lessee may 
not take an allowance for the costs of washing lease production that is 
not royalty bearing.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify ONRR of an allowance based on incurred costs by 
using a separate line entry on the form ONRR-4430.
    (ii) ONRR may require that a lessee submit arm's-length washing 
contracts and related documents. Documents shall be submitted within a 
reasonable time, as determined by ONRR.
    (2) Non-arm's-length or no contract. (i) The lessee must notify 
ONRR of an allowance based on the incurred costs by using a separate 
line entry on the form ONRR-4430.
    (ii) For new washing facilities or arrangements, the lessee's 
initial washing deduction shall include estimates of the allowable coal 
washing costs for the applicable period. Cost estimates shall be based 
upon the most recently available operations data for the washing system 
or, if such data are not available, the lessee shall use estimates 
based upon industry data for similar washing systems.
    (iii) Upon request by ONRR, the lessee shall submit all data used 
to prepare the allowance deduction. The data shall be provided within a 
reasonable period of time, as determined by ONRR.
    (d) Interest and assessments. (1) If a lessee nets a washing 
allowance on the form ONRR-4430, then the lessee shall be assessed an 
amount up to 10 percent of the allowance netted not to exceed $250 per 
lease sales type code per sales period.
    (2) If a lessee erroneously reports a washing allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be 
determined in accordance with Sec.  [thinsp]1218.202 of this chapter.
    (e) Adjustments. (1) If the actual coal washing allowance is less 
than the amount the lessee has taken on form ONRR-4430 for each month 
during the allowance reporting period, the lessee shall pay additional 
royalties due plus interest computed under Sec.  [thinsp]1218.202 of 
this chapter from the date when the lessee took the deduction to the 
date the lessee repays the difference to ONRR. If the actual washing 
allowance is greater than the amount the lessee has taken on form ONRR-
4430 for each month during the allowance reporting period, the lessee 
shall be entitled to a credit without interest.
    (2) The lessee must submit a corrected form ONRR-4430 to reflect 
actual costs, together with any payment, in accordance with 
instructions provided by ONRR.
    (f) Other washing cost determinations. The provisions of this 
section shall apply to determine washing costs when establishing value 
using a net-back valuation procedure or any other procedure that 
requires deduction of washing costs.


Sec.  [thinsp]1206.260  Allocation of washed coal.

    (a) When coal is subjected to washing, the washed coal must be 
allocated to the leases from which it was extracted.
    (b) When the net output of coal from a washing plant is derived 
from coal obtained from only one lease, the quantity of washed coal 
allocable to the lease will be based on the net output of the washing 
plant.
    (c) When the net output of coal from a washing plant is derived 
from coal obtained from more than one lease, unless determined 
otherwise by BLM, the quantity of net output of washed coal allocable 
to each lease will be based on the ratio of measured quantities of coal 
delivered to the washing plant and washed from each lease compared to 
the total measured quantities of coal delivered to the washing plant 
and washed.


Sec.  [thinsp]1206.261  Transportation allowances--general.

    (a) For ad valorem leases subject to Sec.  [thinsp]1206.257 of this 
subpart, where the value for royalty purposes has been determined at a 
point remote from the lease or mine, ONRR shall, as authorized by this 
section, allow a deduction in determining value for royalty purposes 
for the reasonable, actual costs incurred to:
    (1) Transport the coal from a Federal lease to a sales point which 
is remote from both the lease and mine; or
    (2) Transport the coal from a Federal lease to a wash plant when 
that plant is remote from both the lease and mine and, if applicable, 
from the wash plant to a remote sales point. In-mine transportation 
costs shall not be included in the transportation allowance.
    (b) Under no circumstances will the authorized washing allowance 
and the transportation allowance reduce the value for royalty purposes 
to zero.
    (c)(1) When coal transported from a mine to a wash plant is 
eligible for a transportation allowance in accordance with this 
section, the lessee is not required to allocate transportation costs 
between the quantity of clean coal output and the rejected waste 
material. The transportation allowance shall be authorized for the 
total production which is transported. Transportation allowances shall 
be expressed as a cost per ton of cleaned coal transported.
    (2) For coal that is not washed at a wash plant, the transportation 
allowance shall be authorized for the total production which is 
transported. Transportation allowances shall be expressed as a cost per 
ton of coal transported.
    (3) Transportation costs shall only be recognized as allowances 
when the transported coal is sold and royalties are reported and paid.
    (d) If, after a review and/or audit, ONRR determines that a lessee 
has improperly determined a transportation allowance authorized by this 
section, then the lessee shall pay any additional royalties, plus 
interest, determined in accordance with Sec.  [thinsp]1218.202 of this 
chapter, or shall be entitled to a credit, without interest.
    (e) Lessees shall not disproportionately allocate transportation 
costs to Federal leases.


Sec.  [thinsp]1206.262  Determination of transportation allowances.

    (a) Arm's-length contracts. (1) For transportation costs incurred 
by a lessee pursuant to an arm's-length contract, the transportation 
allowance shall be the reasonable, actual costs incurred by the lessee 
for transporting the coal under that contract, subject to monitoring, 
review, audit, and possible future adjustment. The lessee shall have 
the burden of demonstrating that its contract is arm's-length. The 
lessee must claim a transportation allowance by

[[Page 36980]]

reporting it as a separate line entry on the form ONRR-4430.
    (2) In conducting reviews and audits, ONRR will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the transporter for 
the transportation. If the contract reflects more than the total 
consideration paid, then the ONRR may require that the transportation 
allowance be determined in accordance with paragraph (b) of this 
section.
    (3) If ONRR determines that the consideration paid pursuant to an 
arm's-length transportation contract does not reflect the reasonable 
value of the transportation because of misconduct by or between the 
contracting parties, or because the lessee otherwise has breached its 
duty to the lessor to market the production for the mutual benefit of 
the lessee and the lessor, then ONRR shall require that the 
transportation allowance be determined in accordance with paragraph (b) 
of this section. When ONRR determines that the value of the 
transportation may be unreasonable, ONRR will notify the lessee and 
give the lessee an opportunity to provide written information 
justifying the lessee's transportation costs.
    (4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee 
shall convert whatever consideration is paid to a dollar value 
equivalent for the purposes of this section.
    (b) Non-arm's-length or no contract--(1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs transportation services for itself, the 
transportation allowance will be based upon the lessee's reasonable 
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review, 
audit, and possible future adjustment. The lessee must claim a 
transportation allowance by reporting it as a separate line entry on 
the form ONRR-4430. When necessary or appropriate, ONRR may direct a 
lessee to modify its estimated or actual transportation allowance 
deduction.
    (2) The transportation allowance for non-arm's-length or no-
contract situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the transportation system multiplied by the rate of 
return in accordance with paragraph (b)(2)(iv)(B) of this section. 
Allowable capital costs are generally those for depreciable fixed 
assets (including costs of delivery and installation of capital 
equipment) which are an integral part of the transportation system.
    (i) Allowable operating expenses include: Operations supervision 
and engineering; operations labor; fuel; utilities; materials; ad 
valorem property taxes; rent; supplies; and any other directly 
allocable and attributable operating expense which the lessee can 
document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which 
the lessee can document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the transportation system is an allowable expense. State 
and Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this 
section. After a lessee has elected to use either method for a 
transportation system, the lessee may not later elect to change to the 
other alternative without approval of ONRR.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, 
whichever is appropriate, or a unit of production method. After an 
election is made, the lessee may not change methods without ONRR 
approval. A change in ownership of a transportation system shall not 
alter the depreciation schedule established by the original 
transporter/lessee for purposes of the allowance calculation. With or 
without a change in ownership, a transportation system shall be 
depreciated only once. Equipment shall not be depreciated below a 
reasonable salvage value.
    (B) ONRR shall allow as a cost an amount equal to the allowable 
capital investment in the transportation system multiplied by the rate 
of return determined pursuant to paragraph (b)(2)(B)(v) of this 
section. No allowance shall be provided for depreciation. This 
alternative shall apply only to transportation facilities first placed 
in service or acquired after March 1, 1989.
    (v) The rate of return must be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return must be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month for which the allowance is applicable. The rate must be 
redetermined at the beginning of each subsequent calendar year.
    (3) A lessee may apply to ONRR for exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) and 
(2) of this section. ONRR will grant the exception only if the lessee 
has a rate for the transportation approved by a Federal agency or by a 
State regulatory agency (for Federal leases). ONRR shall deny the 
exception request if it determines that the rate is excessive as 
compared to arm's-length transportation charges by systems, owned by 
the lessee or others, providing similar transportation services in that 
area. If there are no arm's-length transportation charges, ONRR shall 
deny the exception request if:
    (i) No Federal or State regulatory agency costs analysis exists and 
the Federal or State regulatory agency, as applicable, has declined to 
investigate under ONRR timely objections upon filing; and
    (ii) The rate significantly exceeds the lessee's actual costs for 
transportation as determined under this section.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) The 
lessee must notify ONRR of an allowance based on incurred costs by 
using a separate line entry on the form ONRR-4430.
    (ii) ONRR may require that a lessee submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents. Documents shall be submitted within a reasonable 
time, as determined by ONRR.
    (2) Non-arm's-length or no contract--(i) The lessee must notify 
ONRR of an allowance based on the incurred costs by using a separate 
line entry on form ONRR-4430.
    (ii) For new transportation facilities or arrangements, the 
lessee's initial deduction shall include estimates of the allowable 
coal transportation costs for the applicable period. Cost estimates 
shall be based upon the most recently available operations data for the 
transportation system or, if such data are not available, the lessee 
shall use estimates based upon industry data for similar transportation 
systems.
    (iii) Upon request by ONRR, the lessee shall submit all data used 
to prepare the allowance deduction. The data shall be provided within a 
reasonable period of time, as determined by ONRR.

[[Page 36981]]

    (iv) If the lessee is authorized to use its Federal- or State-
agency-approved rate as its transportation cost in accordance with 
paragraph (b)(3) of this section, it shall follow the reporting 
requirements of paragraph (c)(1) of this section.
    (d) Interest and assessments. (1) If a lessee nets a transportation 
allowance on form ONRR-4430, the lessee shall be assessed an amount of 
up to 10 percent of the allowance netted not to exceed $250 per lease 
sales type code per sales period.
    (2) If a lessee erroneously reports a transportation allowance 
which results in an underpayment of royalties, interest shall be paid 
on the amount of that underpayment.
    (3) Interest required to be paid by this section shall be 
determined in accordance with Sec.  [thinsp]1218.202 of this chapter.
    (e) Adjustments. (1) If the actual coal transportation allowance is 
less than the amount the lessee has taken on form ONRR-4430 for each 
month during the allowance reporting period, the lessee shall pay 
additional royalties due plus interest computed under Sec.  
[thinsp]1218.202 of this chapter from the date when the lessee took the 
deduction to the date the lessee repays the difference to ONRR. If the 
actual transportation allowance is greater than amount the lessee has 
taken on form ONRR-4430 for each month during the allowance reporting 
period, the lessee shall be entitled to a credit without interest.
    (2) The lessee must submit a corrected form ONRR-4430 to reflect 
actual costs, together with any payments, in accordance with 
instructions provided by ONRR.
    (f) Other transportation cost determinations. The provisions of 
this section shall apply to determine transportation costs when 
establishing value using a net-back valuation procedure or any other 
procedure that requires deduction of transportation costs.


Sec.  [thinsp]1206.263   [Reserved]


Sec.  [thinsp]1206.264  In-situ and surface gasification and 
liquefaction operations.

    If an ad valorem Federal coal lease is developed by in-situ or 
surface gasification or liquefaction technology, the lessee shall 
propose the value of coal for royalty purposes to ONRR. The ONRR will 
review the lessee's proposal and issue a value determination. The 
lessee may use its proposed value until ONRR issues a value 
determination.


Sec.  [thinsp]1206.265  Value enhancement of marketable coal.

    If, prior to use, sale, or other disposition, the lessee enhances 
the value of coal after the coal has been placed in marketable 
condition in accordance with Sec.  [thinsp]1206.257(h) of this subpart, 
the lessee shall notify ONRR that such processing is occurring or will 
occur. The value of that production shall be determined as follows:
    (a) A value established for the feedstock coal in marketable 
condition by application of the provisions of Sec.  
[thinsp]1206.257(c)(2)(i) through (iv) of this subpart; or,
    (b) In the event that a value cannot be established in accordance 
with paragraph (a) of this section, then the value of production will 
be determined in accordance with Sec.  [thinsp]1206.257(c)(2)(v) of 
this subpart and the value shall be the lessee's gross proceeds 
accruing from the disposition of the enhanced product, reduced by ONRR-
approved processing costs and procedures including a rate of return on 
investment equal to two times the Standard and Poor's BBB bond rate 
applicable under Sec.  [thinsp]1206.259(b)(2)(v) of this subpart.

0
9. Revise subpart J to read as follows:
Subpart J--Indian Coal
Sec.
1206.450 Purpose and scope.
1206.451 Definitions.
1206.452 Coal subject to royalties--general provisions.
1206.453 Quality and quantity measurement standards for reporting 
and paying royalties.
1206.454 Point of royalty determination.
1206.455 Valuation standards for cents-per-ton leases.
1206.456 Valuation standards for ad valorem leases.
1206.457 Washing allowances--general.
1206.458 Determination of washing allowances.
1206.459 Allocation of washed coal.
1206.460 Transportation allowances--general.
1206.461 Determination of transportation allowances.
1206.462 [Reserved]
1206.463 In-situ and surface gasification and liquefaction 
operations.
1206.464 Value enhancement of marketable coal.

Subpart J--Indian Coal


Sec.  [thinsp]1206.450  Purpose and scope.

    (a) This subpart prescribes the procedures to establish the value, 
for royalty purposes, of all coal from Indian Tribal and allotted 
leases (except leases on the Osage Indian Reservation, Osage County, 
Oklahoma).
    (b) If the specific provisions of any statute, treaty, or 
settlement agreement between the Indian lessor and a lessee resulting 
from administrative or judicial litigation, or any coal lease subject 
to the requirements of this subpart, are inconsistent with any 
regulation in this subpart, then the statute, treaty, lease provision, 
or settlement shall govern to the extent of that inconsistency.
    (c) All royalty payments are subject to later audit and adjustment.
    (d) The regulations in this subpart are intended to ensure that the 
trust responsibilities of the United States with respect to the 
administration of Indian coal leases are discharged in accordance with 
the requirements of the governing mineral leasing laws, treaties, and 
lease terms.


Sec.  [thinsp]1206.451  Definitions.

    Ad valorem lease means a lease where the royalty due to the lessor 
is based upon a percentage of the amount or value of the coal.
    Allowance means an approved, or an ONRR-initially accepted 
deduction in determining value for royalty purposes. Coal washing 
allowance means an allowance for the reasonable, actual costs incurred 
by the lessee for coal washing, or an approved or ONRR-initially 
accepted deduction for the costs of washing coal, determined pursuant 
to this subpart. Transportation allowance means an allowance for the 
reasonable, actual costs incurred by the lessee for moving coal to a 
point of sale or point of delivery remote from both the lease and mine 
or wash plant, or an approved ONRR-initially accepted deduction for 
costs of such transportation, determined pursuant to this subpart.
    Area means a geographic region in which coal has similar quality 
and economic characteristics. Area boundaries are not officially 
designated and the areas are not necessarily named.
    Arm's-length contract means a contract or agreement that has been 
arrived at in the marketplace between independent, nonaffiliated 
persons with opposing economic interests regarding that contract. For 
purposes of this subpart, two persons are affiliated if one person 
controls, is controlled by, or is under common control with another 
person. For purposes of this subpart, based on the instruments of 
ownership of the voting securities of an entity, or based on other 
forms of ownership: Ownership in excess of 50 percent constitutes 
control; ownership of 10 through 50 percent creates a presumption of 
control; and ownership of less than 10 percent creates a presumption of 
noncontrol which ONRR may rebut if it demonstrates actual or legal 
control, including the existence of interlocking directorates.

[[Page 36982]]

Notwithstanding any other provisions of this subpart, contracts between 
relatives, either by blood or by marriage, are not arm's-length 
contracts. ONRR may require the lessee to certify ownership control. To 
be considered arm's-length for any production month, a contract must 
meet the requirements of this definition for that production month, as 
well as when the contract was executed.
    Audit means a review, conducted in accordance with generally 
accepted accounting and auditing standards, of royalty payment 
compliance activities of lessees or other interest holders who pay 
royalties, rents, or bonuses on Indian leases.
    BIA means the Bureau of Indian Affairs of the Department of the 
Interior.
    BLM means the Bureau of Land Management of the Department of the 
Interior.
    Coal means coal of all ranks from lignite through anthracite.
    Coal washing means any treatment to remove impurities from coal. 
Coal washing may include, but is not limited to, operations such as 
flotation, air, water, or heavy media separation; drying; and related 
handling (or combination thereof).
    Contract means any oral or written agreement, including amendments 
or revisions thereto, between two or more persons and enforceable by 
law that with due consideration creates an obligation.
    Gross proceeds (for royalty payment purposes) means the total 
monies and other consideration accruing to a coal lessee for the 
production and disposition of the coal produced. Gross proceeds 
includes, but is not limited to, payments to the lessee for certain 
services such as crushing, sizing, screening, storing, mixing, loading, 
treatment with substances including chemicals or oils, and other 
preparation of the coal to the extent that the lessee is obligated to 
perform them at no cost to the Indian lessor. Gross proceeds, as 
applied to coal, also includes but is not limited to reimbursements for 
royalties, taxes or fees, and other reimbursements. Tax reimbursements 
are part of the gross proceeds accruing to a lessee even though the 
Indian royalty interest may be exempt from taxation. Monies and other 
consideration, including the forms of consideration identified in this 
paragraph, to which a lessee is contractually or legally entitled but 
which it does not seek to collect through reasonable efforts are also 
part of gross proceeds.
    Indian allottee means any Indian for whom land or an interest in 
land is held in trust by the United States or who holds title subject 
to Federal restriction against alienation.
    Indian Tribe means any Indian Tribe, band, nation, pueblo, 
community, rancheria, colony, or other group of Indians for which any 
land or interest in land is held in trust by the United States or which 
is subject to Federal restriction against alienation.
    Lease means any contract, profit-share arrangement, joint venture, 
or other agreement issued or approved by the United States for an 
Indian coal resource under a mineral leasing law that authorizes 
exploration for, development or extraction of, or removal of coal--or 
the land covered by that authorization, whichever is required by the 
context.
    Lessee means any person to whom the Indian Tribe or an Indian 
allottee issues a lease, and any person who has been assigned an 
obligation to make royalty or other payments required by the lease. 
This includes any person who has an interest in a lease as well as an 
operator or payor who has no interest in the lease but who has assumed 
the royalty payment responsibility.
    Like-quality coal means coal that has similar chemical and physical 
characteristics.
    Marketable condition means coal that is sufficiently free from 
impurities and otherwise in a condition that it will be accepted by a 
purchaser under a sales contract typical for that area.
    Mine means an underground or surface excavation or series of 
excavations and the surface or underground support facilities that 
contribute directly or indirectly to mining, production, preparation, 
and handling of lease products.
    Net-back method means a method for calculating market value of coal 
at the lease or mine. Under this method, costs of transportation, 
washing, handling, etc., are deducted from the ultimate proceeds 
received for the coal at the first point at which reasonable values for 
the coal may be determined by a sale pursuant to an arm's-length 
contract or by comparison to other sales of coal, to ascertain value at 
the mine.
    Net output means the quantity of washed coal that a washing plant 
produces.
    ONRR means the Office of Natural Resources Revenue of the 
Department of the Interior.
    Person means by individual, firm, corporation, association, 
partnership, consortium, or joint venture.
    Sales type code means the contract type or general disposition 
(e.g., arm's-length or non-arm's-length) of production from the lease. 
The sales type code applies to the sales contract, or other 
disposition, and not to the arm's-length or non-arm's-length nature of 
a transportation or washing allowance.
    Spot market price means the price received under any sales 
transaction when planned or actual deliveries span a short period of 
time, usually not exceeding one year.


Sec.  [thinsp]1206.452  Coal subject to royalties--general provisions.

    (a) All coal (except coal unavoidably lost as determined by BLM 
pursuant to 43 CFR group 3400) from an Indian lease subject to this 
part is subject to royalty. This includes coal used, sold, or otherwise 
disposed of by the lessee on or off the lease.
    (b) If a lessee receives compensation for unavoidably lost coal 
through insurance coverage or other arrangements, royalties at the rate 
specified in the lease are to be paid on the amount of compensation 
received for the coal. No royalty is due on insurance compensation 
received by the lessee for other losses.
    (c) If waste piles or slurry ponds are reworked to recover coal, 
the lessee shall pay royalty at the rate specified in the lease at the 
time the recovered coal is used, sold, or otherwise finally disposed 
of. The royalty rate shall be that rate applicable to the production 
method used to initially mine coal in the waste pile or slurry pond; 
i.e., underground mining method or surface mining method. Coal in waste 
pits or slurry ponds initially mined from Indian leases shall be 
allocated to such leases regardless of whether it is stored on Indian 
lands. The lessee shall maintain accurate records to determine to which 
individual Indian lease coal in the waste pit or slurry pond should be 
allocated. However, nothing in this section requires payment of a 
royalty on coal for which a royalty has already been paid.


Sec.  [thinsp]1206.453  Quality and quantity measurement standards for 
reporting and paying royalties.

    For all leases subject to this subpart, the quantity of coal on 
which royalty is due shall be measured in short tons (of 2,000 pounds 
each) by methods prescribed by the BLM. Coal quantity information will 
be reported on appropriate forms required under 30 CFR part 1210--Forms 
and Reports.


Sec.  1206.454  Point of royalty determination.

    (a) For all leases subject to this subpart, royalty shall be 
computed on the basis of the quantity and quality of Indian coal in 
marketable condition measured at the point of royalty

[[Page 36983]]

measurement as determined jointly by BLM and ONRR.
    (b) Coal produced and added to stockpiles or inventory does not 
require payment of royalty until such coal is later used, sold, or 
otherwise finally disposed of. ONRR may ask BLM or BIA to increase the 
lease bond to protect the lessor's interest when BLM determines that 
stockpiles or inventory become excessive so as to increase the risk of 
degradation of the resource.
    (c) The lessee shall pay royalty at a rate specified in the lease 
at the time the coal is used, sold, or otherwise finally disposed of, 
unless otherwise provided for at Sec.  [thinsp]1206.455(d) of this 
subpart.


Sec.  [thinsp]1206.455  Valuation standards for cents-per-ton leases.

    (a) This section is applicable to coal leases on Indian Tribal and 
allotted Indian lands (except leases on the Osage Indian Reservation, 
Osage County, Oklahoma) which provide for the determination of royalty 
on a cents-per-ton (or other quantity) basis.
    (b) The royalty for coal from leases subject to this section shall 
be based on the dollar rate per ton prescribed in the lease. That 
dollar rate shall be applicable to the actual quantity of coal used, 
sold, or otherwise finally disposed of, including coal which is 
avoidably lost as determined by BLM pursuant to 43 CFR part 3400.
    (c) For leases subject to this section, there shall be no 
allowances for transportation, removal of impurities, coal washing, or 
any other processing or preparation of the coal.
    (d) When a coal lease is readjusted pursuant to 43 CFR part 3400 
and the royalty valuation method changes from a cents-per-ton basis to 
an ad valorem basis, coal which is produced prior to the effective date 
of readjustment and sold or used within 30 days of the effective date 
of readjustment shall be valued pursuant to this section. All coal that 
is not used, sold, or otherwise finally disposed of within 30 days 
after the effective date of readjustment shall be valued pursuant to 
the provisions of Sec.  [thinsp]1206.456 of this subpart, and royalties 
shall be paid at the royalty rate specified in the readjusted lease.


Sec.  [thinsp]1206.456  Valuation standards for ad valorem leases.

    (a) This section is applicable to coal leases on Indian Tribal and 
allotted Indian lands (except leases on the Osage Indian Reservation, 
Osage County, Oklahoma) which provide for the determination of royalty 
as a percentage of the amount of value of coal (ad valorem). The value 
for royalty purposes of coal from such leases shall be the value of 
coal determined pursuant to this section, less applicable coal washing 
allowances and transportation allowances determined pursuant to 
Sec. Sec.  [thinsp]1206.457 through 1206.461 of this subpart, or any 
allowance authorized by Sec.  [thinsp]1206.464 of this subpart. The 
royalty due shall be equal to the value for royalty purposes multiplied 
by the royalty rate in the lease.
    (b)(1) The value of coal that is sold pursuant to an arm's-length 
contract shall be the gross proceeds accruing to the lessee, except as 
provided in paragraphs (b)(2), (3), and (5) of this section. The lessee 
shall have the burden of demonstrating that its contract is arm's-
length. The value which the lessee reports, for royalty purposes, is 
subject to monitoring, review, and audit.
    (2) In conducting reviews and audits, ONRR will examine whether the 
contract reflects the total consideration actually transferred either 
directly or indirectly from the buyer to the seller for the coal 
produced. If the contract does not reflect the total consideration, 
then ONRR may require that the coal sold pursuant to that contract be 
valued in accordance with paragraph (c) of this section. Value may not 
be based on less than the gross proceeds accruing to the lessee for the 
coal production, including the additional consideration.
    (3) If ONRR determines that the gross proceeds accruing to the 
lessee pursuant to an arm's-length contract do not reflect the 
reasonable value of the production because of misconduct by or between 
the contracting parties, or because the lessee otherwise has breached 
its duty to the lessor to market the production for the mutual benefit 
of the lessee and the lessor, then ONRR shall require that the coal 
production be valued pursuant to paragraphs (c)(2)(ii), (iii), (iv), or 
(v) of this section, and in accordance with the notification 
requirements of paragraph (d)(3) of this section. When ONRR determines 
that the value may be unreasonable, ONRR will notify the lessee and 
give the lessee an opportunity to provide written information 
justifying the lessee's reported coal value.
    (4) ONRR may require a lessee to certify that its arm's-length 
contract provisions include all of the consideration to be paid by the 
buyer, either directly or indirectly, for the coal production.
    (5) The value of production for royalty purposes shall not include 
payments received by the lessee pursuant to a contract which the lessee 
demonstrates, to ONRR's satisfaction, were not part of the total 
consideration paid for the purchase of coal production.
    (c)(1) The value of coal from leases subject to this section and 
which is not sold pursuant to an arm's-length contract shall be 
determined in accordance with this section.
    (2) If the value of the coal cannot be determined pursuant to 
paragraph (b) of this section, then the value shall be determined 
through application of other valuation criteria. The criteria shall be 
considered in the following order, and the value shall be based upon 
the first applicable criterion:
    (i) The gross proceeds accruing to the lessee pursuant to a sale 
under its non-arm's-length contract (or other disposition of produced 
coal by other than an arm's-length contract), provided that those gross 
proceeds are within the range of the gross proceeds derived from, or 
paid under, comparable arm's-length contracts between buyers and 
sellers neither of whom is affiliated with the lessee for sales, 
purchases, or other dispositions of like-quality coal produced in the 
area. In evaluating the comparability of arm's-length contracts for the 
purposes of these regulations, the following factors shall be 
considered: Price, time of execution, duration, market or markets 
served, terms, quality of coal, quantity, and such other factors as may 
be appropriate to reflect the value of the coal;
    (ii) Prices reported for that coal to a public utility commission;
    (iii) Prices reported for that coal to the Energy Information 
Administration of the Department of Energy;
    (iv) Other relevant matters including, but not limited to, 
published or publicly available spot market prices, or information 
submitted by the lessee concerning circumstances unique to a particular 
lease operation or the salability of certain types of coal;
    (v) If a reasonable value cannot be determined using paragraphs 
(c)(2)(i), (ii), (iii), or (iv) of this section, then a net-back method 
or any other reasonable method shall be used to determine value.
    (3) When the value of coal is determined pursuant to paragraph 
(c)(2) of this section, that value determination shall be consistent 
with the provisions contained in paragraph (b)(5) of this section.
    (d)(1) Where the value is determined pursuant to paragraph (c) of 
this section, that value does not require ONRR's prior approval. 
However, the lessee shall retain all data relevant to the determination 
of royalty value. Such data shall be subject to review and audit, and 
ONRR will direct a lessee to use a different value if it determines 
that the reported value is inconsistent with the requirements of these 
regulations.

[[Page 36984]]

    (2) An Indian lessee will make available upon request to the 
authorized ONRR or Indian representatives, or to the Inspector General 
of the Department of the Interior or other persons authorized to 
receive such information, arm's-length sales and sales quantity data 
for like-quality coal sold, purchased, or otherwise obtained by the 
lessee from the area.
    (3) A lessee shall notify ONRR if it has determined value pursuant 
to paragraphs (c)(2)(ii), (iii), (iv), or (v) of this section. The 
notification shall be by letter to the Director for Office of Natural 
Resources Revenue or his/her designee. The letter shall identify the 
valuation method to be used and contain a brief description of the 
procedure to be followed. The notification required by this section is 
a one-time notification due no later than the month the lessee first 
reports royalties on the form ONRR-4430 using a valuation method 
authorized by paragraphs (c)(2)(ii), (iii), (iv), or (v) of this 
section, and each time there is a change in a method under paragraphs 
(c)(2)(iv) or (v) of this section.
    (e) If ONRR determines that a lessee has not properly determined 
value, the lessee shall be liable for the difference, if any, between 
royalty payments made based upon the value it has used and the royalty 
payments that are due based upon the value established by ONRR. The 
lessee shall also be liable for interest computed pursuant to 30 CFR 
1218.202. If the lessee is entitled to a credit, ONRR will provide 
instructions for the taking of that credit.
    (f) The lessee may request a value determination from ONRR. In that 
event, the lessee shall propose to ONRR a value determination method, 
and may use that method in determining value for royalty purposes until 
ONRR issues its decision. The lessee shall submit all available data 
relevant to its proposal. ONRR shall expeditiously determine the value 
based upon the lessee's proposal and any additional information ONRR 
deems necessary. That determination shall remain effective for the 
period stated therein. After ONRR issues its determination, the lessee 
shall make the adjustments in accordance with paragraph (e) of this 
section.
    (g) Notwithstanding any other provisions of this section, under no 
circumstances shall the value for royalty purposes be less than the 
gross proceeds accruing to the lessee for the disposition of produced 
coal less applicable provisions of paragraph (b)(5) of this section and 
less applicable allowances determined pursuant to Sec. Sec.  
[thinsp]1206.457 through 1206.461 and[thinsp]1206.464 of this subpart.
    (h) The lessee is required to place coal in marketable condition at 
no cost to the Indian lessor. Where the value established pursuant to 
this section is determined by a lessee's gross proceeds, that value 
shall be increased to the extent that the gross proceeds has been 
reduced because the purchaser, or any other person, is providing 
certain services, the cost of which ordinarily is the responsibility of 
the lessee to place the coal in marketable condition.
    (i) Value shall be based on the highest price a prudent lessee can 
receive through legally enforceable claims under its contract. Absent 
contract revision or amendment, if the lessee fails to take proper or 
timely action to receive prices or benefits to which it is entitled, it 
must pay royalty at a value based upon that obtainable price or 
benefit. Contract revisions or amendments shall be in writing and 
signed by all parties to an arm's-length contract, and may be 
retroactively applied to value for royalty purposes for a period not to 
exceed two years, unless ONRR approves a longer period. If the lessee 
makes timely application for a price increase allowed under its 
contract but the purchaser refuses, and the lessee takes reasonable 
measures, which are documented, to force purchaser compliance, the 
lessee will owe no additional royalties unless or until monies or 
consideration resulting from the price increase are received. This 
paragraph shall not be construed to permit a lessee to avoid its 
royalty payment obligation in situations where a purchaser fails to 
pay, in whole or in part or timely, for a quantity of coal.
    (j) Notwithstanding any provision in these regulations to the 
contrary, no review, reconciliation, monitoring, or other like process 
that results in a redetermination by ONRR of value under this section 
shall be considered final or binding as against the Indian Tribes or 
allottees until the audit period is formally closed.
    (k) Certain information submitted to ONRR to support valuation 
proposals, including transportation, coal washing, or other allowances 
pursuant to Sec. Sec.  [thinsp]1206.457 through 1206.461 and 1206.464 
of this subpart, is exempted from disclosure by the Freedom of 
Information Act, 5 U.S.C. 522. Any data specified by the Act to be 
privileged, confidential, or otherwise exempt shall be maintained in a 
confidential manner in accordance with applicable law and regulations. 
All requests for information about determinations made under this part 
are to be submitted in accordance with the Freedom of Information Act 
regulation of the Department of the Interior, 43 CFR part 2. Nothing in 
this section is intended to limit or diminish in any manner whatsoever 
the right of an Indian lessor to obtain any and all information as such 
lessor may be lawfully entitled from ONRR or such lessor's lessee 
directly under the terms of the lease or applicable law.


Sec.  [thinsp]1206.457  Washing allowances--general.

    (a) For ad valorem leases subject to Sec.  [thinsp]1206.456 of this 
subpart, ONRR shall, as authorized by this section, allow a deduction 
in determining value for royalty purposes for the reasonable, actual 
costs incurred to wash coal, unless the value determined pursuant to 
Sec.  [thinsp]1206.456 of this subpart was based upon like-quality 
unwashed coal. Under no circumstances will the authorized washing 
allowance and the transportation allowance reduce the value for royalty 
purposes to zero.
    (b) If ONRR determines that a lessee has improperly determined a 
washing allowance authorized by this section, then the lessee shall be 
liable for any additional royalties, plus interest determined in 
accordance with Sec.  [thinsp]1218.202 of this chapter, or shall be 
entitled to a credit, without interest.
    (c) Lessees shall not disproportionately allocate washing costs to 
Indian leases.
    (d) No cost normally associated with mining operations and which 
are necessary for placing coal in marketable condition shall be allowed 
as a cost of washing.
    (e) Coal washing costs shall only be recognized as allowances when 
the washed coal is sold and royalties are reported and paid.


Sec.  [thinsp]1206.458  Determination of washing allowances.

    (a) Arm's-length contracts. (1) For washing costs incurred by a 
lessee pursuant to an arm's-length contract, the washing allowance 
shall be the reasonable actual costs incurred by the lessee for washing 
the coal under that contract, subject to monitoring, review, audit, and 
possible future adjustment. ONRR's prior approval is not required 
before a lessee may deduct costs incurred under an arm's-length 
contract. However, before any deduction may be taken, the lessee must 
submit a completed page one of form ONRR-4292, Coal Washing Allowance 
Report, in accordance with paragraph (c)(1) of this section. A washing 
allowance may be claimed retroactively for a period of not more than 3 
months prior to the first day of the month that form ONRR-4292 is filed 
with ONRR, unless ONRR approves a longer period upon a showing of good 
cause by the lessee.

[[Page 36985]]

    (2) In conducting reviews and audits, ONRR will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the washer for the 
washing. If the contract reflects more than the total consideration 
paid, then ONRR may require that the washing allowance be determined in 
accordance with paragraph (b) of this section.
    (3) If ONRR determines that the consideration paid pursuant to an 
arm's-length washing contract does not reflect the reasonable value of 
the washing because of misconduct by or between the contracting 
parties, or because the lessee otherwise has breached its duty to the 
lessor to market the production for the mutual benefit of the lessee 
and the lessor, then ONRR shall require that the washing allowance be 
determined in accordance with paragraph (b) of this section. When ONRR 
determines that the value of the washing may be unreasonable, ONRR will 
notify the lessee and give the lessee an opportunity to provide written 
information justifying the lessee's washing costs.
    (4) Where the lessee's payments for washing under an arm's-length 
contract are not based on a dollar-per-unit basis, the lessee shall 
convert whatever consideration is paid to a dollar value equivalent. 
Washing allowances shall be expressed as a cost per ton of coal washed.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs washing for itself, the washing allowance 
will be based upon the lessee's reasonable actual costs. All washing 
allowances deducted under a non-arm's-length or no contract situation 
are subject to monitoring, review, audit, and possible future 
adjustment. Prior ONRR approval of washing allowances is not required 
for non-arm's-length or no contract situations. However, before any 
estimated or actual deduction may be taken, the lessee must submit a 
completed form ONRR-4292 in accordance with paragraph (c)(2) of this 
section. A washing allowance may be claimed retroactively for a period 
of not more than 3 months prior to the first day of the month that form 
ONRR-4292 is filed with ONRR, unless ONRR approves a longer period upon 
a showing of good cause by the lessee. ONRR will monitor the allowance 
deduction to ensure that deductions are reasonable and allowable. When 
necessary or appropriate, ONRR may direct a lessee to modify its actual 
washing allowance.
    (2) The washing allowance for non-arm's-length or no contract 
situations shall be based upon the lessee's actual costs for washing 
during the reported period, including operating and maintenance 
expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the wash plant multiplied by the rate of return in 
accordance with paragraph (b)(2)(iv)(B) of this section. Allowable 
capital costs are generally those for depreciable fixed assets 
(including costs of delivery and installation of capital equipment) 
which are an integral part of the wash plant.
    (i) Allowable operating expenses include: Operations supervision 
and engineering; operations labor; fuel; utilities; materials; ad 
valorem property taxes; rent; supplies; and any other directly 
allocable and attributable operating expense which the lessee can 
document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
wash plant; maintenance of equipment; maintenance labor; and other 
directly allocable and attributable maintenance expenses which the 
lessee can document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the wash plant is an allowable expense. State and 
Federal income taxes and severance taxes, including royalties, are not 
allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this 
section. After a lessee has elected to use either method for a wash 
plant, the lessee may not later elect to change to the other 
alternative without approval of ONRR.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the wash plant services, whichever is 
appropriate, or a unit of production method. After an election is made, 
the lessee may not change methods without ONRR approval. A change in 
ownership of a wash plant shall not alter the depreciation schedule 
established by the original operator/lessee for purposes of the 
allowance calculation. With or without a change in ownership, a wash 
plant shall be depreciated only once. Equipment shall not be 
depreciated below a reasonable salvage value.
    (B) ONRR shall allow as a cost an amount equal to the allowable 
capital investment in the wash plant multiplied by the rate of return 
determined pursuant to paragraph (b)(2)(v) of this section. No 
allowance shall be provided for depreciation. This alternative shall 
apply only to plants first placed in service or acquired after March 1, 
1989.
    (v) The rate of return shall be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return shall be the monthly 
average rate as published in Standard and Poor's Bond Guide for the 
first month of the reporting period for which the allowance is 
applicable and shall be effective during the reporting period. The rate 
shall be redetermined at the beginning of each subsequent washing 
allowance reporting period (which is determined pursuant to paragraph 
(c)(2) of this section).
    (3) The washing allowance for coal shall be determined based on the 
lessee's reasonable and actual cost of washing the coal. The lessee may 
not take an allowance for the costs of washing lease production that is 
not royalty bearing.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) With 
the exception of those washing allowances specified in paragraphs 
(c)(1)(v) and (vi) of this section, the lessee shall submit page one of 
the initial form ONRR-4292 prior to, or at the same time, as the 
washing allowance determined pursuant to an arm's-length contract is 
reported on form ONRR-4430, Solid Minerals Production and Royalty 
Report. A form ONRR-4292 received by the end of the month that the form 
ONRR-4430 is due shall be considered to be received timely.
    (ii) The initial form ONRR-4292 shall be effective for a reporting 
period beginning the month that the lessee is first authorized to 
deduct a washing allowance and shall continue until the end of the 
calendar year, or until the applicable contract or rate terminates or 
is modified or amended, whichever is earlier.
    (iii) After the initial reporting period and for succeeding 
reporting periods, lessees must submit page one of form ONRR-4292 
within 3 months after the end of the calendar year, or after the 
applicable contract or rate terminates or is modified or amended, 
whichever is earlier, unless ONRR approves a longer period (during 
which period the lessee shall continue to use the allowance from the 
previous reporting period).
    (iv) ONRR may require that a lessee submit arm's-length washing 
contracts and related documents. Documents shall be submitted within a 
reasonable time, as determined by ONRR.
    (v) Washing allowances which are based on arm's-length contracts 
and

[[Page 36986]]

which are in effect at the time these regulations become effective will 
be allowed to continue until such allowances terminate. For the 
purposes of this section, only those allowances that have been approved 
by ONRR in writing shall qualify as being in effect at the time these 
regulations become effective.
    (vi) ONRR may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (2) Non-arm's-length or no contract. (i) With the exception of 
those washing allowances specified in paragraphs (c)(2)(v) and (vii) of 
this section, the lessee shall submit an initial form ONRR-4292 prior 
to, or at the same time as, the washing allowance determined pursuant 
to a non-arm's-length contract or no contract situation is reported on 
form ONRR-4430, Solid Minerals Production and Royalty Report. A form 
ONRR-4292 received by the end of the month that the form ONRR-4430 is 
due shall be considered to be timely received. The initial reporting 
may be based on estimated costs.
    (ii) The initial form ONRR-4292 shall be effective for a reporting 
period beginning the month that the lessee first is authorized to 
deduct a washing allowance and shall continue until the end of the 
calendar year, or until the washing under the non-arm's-length contract 
or the no contract situation terminates, whichever is earlier.
    (iii) For calendar-year reporting periods succeeding the initial 
reporting period, the lessee shall submit a completed form ONRR-4292 
containing the actual costs for the previous reporting period. If coal 
washing is continuing, the lessee shall include on form ONRR-4292 its 
estimated costs for the next calendar year. The estimated coal washing 
allowance shall be based on the actual costs for the previous period 
plus or minus any adjustments which are based on the lessee's knowledge 
of decreases or increases which will affect the allowance. Form ONRR-
4292 must be received by ONRR within 3 months after the end of the 
previous reporting period, unless ONRR approves a longer period (during 
which period the lessee shall continue to use the allowance from the 
previous reporting period).
    (iv) For new wash plants, the lessee's initial form ONRR-4292 shall 
include estimates of the allowable coal washing costs for the 
applicable period. Cost estimates shall be based upon the most recently 
available operations data for the plant, or if such data are not 
available, the lessee shall use estimates based upon industry data for 
similar coal wash plants.
    (v) Washing allowances based on non-arm's-length or no contract 
situations which are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For the purposes of this section, only those allowances that have been 
approved by ONRR in writing shall qualify as being in effect at the 
time these regulations become effective.
    (vi) Upon request by ONRR, the lessee shall submit all data used by 
the lessee to prepare its forms ONRR-4292. The data shall be provided 
within a reasonable period of time, as determined by ONRR.
    (vii) ONRR may establish, in appropriate circumstances, reporting 
requirements which are different from the requirements of this section.
    (3) ONRR may establish coal washing allowance reporting dates for 
individual leases different from those specified in this subpart in 
order to provide more effective administration. Lessees will be 
notified of any change in their reporting period.
    (4) Washing allowances must be reported as a separate line on the 
form ONRR-4430, unless ONRR approves a different reporting procedure.
    (d) Interest assessments for incorrect or late reports and failure 
to report. (1) If a lessee deducts a washing allowance on its form 
ONRR-4430 without complying with the requirements of this section, the 
lessee shall be liable for interest on the amount of such deduction 
until the requirements of this section are complied with. The lessee 
also shall repay the amount of any allowance which is disallowed by 
this section.
    (2) If a lessee erroneously reports a washing allowance which 
results in an underpayment of royalties, interest shall be paid on the 
amount of that underpayment.
    (3) Interest required to be paid by this section shall be 
determined in accordance with Sec.  [thinsp]1218.202 of this chapter.
    (e) Adjustments. (1) If the actual coal washing allowance is less 
than the amount the lessee has taken on form ONRR-4430 for each month 
during the allowance form reporting period, the lessee shall be 
required to pay additional royalties due plus interest computed 
pursuant to Sec.  [thinsp]1218.202, retroactive to the first month the 
lessee is authorized to deduct a washing allowance. If the actual 
washing allowance is greater than the amount the lessee has estimated 
and taken during the reporting period, the lessee shall be entitled to 
a credit, without interest.
    (2) The lessee must submit a corrected form ONRR-4430 to reflect 
actual costs, together with any payment, in accordance with 
instructions provided by ONRR.
    (f) Other washing cost determinations. The provisions of this 
section shall apply to determine washing costs when establishing value 
using a net-back valuation procedure or any other procedure that 
requires deduction of washing costs.


Sec.  [thinsp]1206.459  Allocation of washed coal.

    (a) When coal is subjected to washing, the washed coal must be 
allocated to the leases from which it was extracted.
    (b) When the net output of coal from a washing plant is derived 
from coal obtained from only one lease, the quantity of washed coal 
allocable to the lease will be based on the net output of the washing 
plant.
    (c) When the net output of coal from a washing plant is derived 
from coal obtained from more than one lease, unless determined 
otherwise by BLM, the quantity of net output of washed coal allocable 
to each lease will be based on the ratio of measured quantities of coal 
delivered to the washing plant and washed from each lease compared to 
the total measured quantities of coal delivered to the washing plant 
and washed.


Sec.  [thinsp]1206.460  Transportation allowances--general.

    (a) For ad valorem leases subject to Sec.  [thinsp]1206.456 of this 
subpart, where the value for royalty purposes has been determined at a 
point remote from the lease or mine, ONRR shall, as authorized by this 
section, allow a deduction in determining value for royalty purposes 
for the reasonable, actual costs incurred to:
    (1) Transport the coal from an Indian lease to a sales point which 
is remote from both the lease and mine; or
    (2) Transport the coal from an Indian lease to a wash plant when 
that plant is remote from both the lease and mine and, if applicable, 
from the wash plant to a remote sales point. In-mine transportation 
costs shall not be included in the transportation allowance.
    (b) Under no circumstances will the authorized washing allowance 
and the transportation allowance reduce the value for royalty purposes 
to zero.
    (c)(1) When coal transported from a mine to a wash plant is 
eligible for a transportation allowance in accordance with this 
section, the lessee is not required to allocate transportation costs

[[Page 36987]]

between the quantity of clean coal output and the rejected waste 
material. The transportation allowance shall be authorized for the 
total production which is transported. Transportation allowances shall 
be expressed as a cost per ton of cleaned coal transported.
    (2) For coal that is not washed at a wash plant, the transportation 
allowance shall be authorized for the total production which is 
transported. Transportation allowances shall be expressed as a cost per 
ton of coal transported.
    (3) Transportation costs shall only be recognized as allowances 
when the transported coal is sold and royalties are reported and paid.
    (d) If, after a review and/or audit, ONRR determines that a lessee 
has improperly determined a transportation allowance authorized by this 
section, then the lessee shall pay any additional royalties, plus 
interest, determined in accordance with Sec.  [thinsp]1218.202 of this 
chapter, or shall be entitled to a credit, without interest.
    (e) Lessees shall not disproportionately allocate transportation 
costs to Indian leases.


Sec.  [thinsp]1206.461  Determination of transportation allowances.

    (a) Arm's-length contracts. (1) For transportation costs incurred 
by a lessee pursuant to an arm's-length contract, the transportation 
allowance shall be the reasonable, actual costs incurred by the lessee 
for transporting the coal under that contract, subject to monitoring, 
review, audit, and possible future adjustment. ONRR's prior approval is 
not required before a lessee may deduct costs incurred under an arm's-
length contract. However, before any deduction may be taken, the lessee 
must submit a completed page one of form ONRR-4293, Coal Transportation 
Allowance Report, in accordance with paragraph (c)(1) of this section. 
A transportation allowance may be claimed retroactively for a period of 
not more than 3 months prior to the first day of the month that form 
ONRR-4293 is filed with ONRR, unless ONRR approves a longer period upon 
a showing of good cause by the lessee.
    (2) In conducting reviews and audits, ONRR will examine whether the 
contract reflects more than the consideration actually transferred 
either directly or indirectly from the lessee to the transporter for 
the transportation. If the contract reflects more than the total 
consideration paid, then ONRR may require that the transportation 
allowance be determined in accordance with paragraph (b) of this 
section.
    (3) If ONRR determines that the consideration paid pursuant to an 
arm's-length transportation contract does not reflect the reasonable 
value of the transportation because of misconduct by or between the 
contracting parties, or because the lessee otherwise has breached its 
duty to the lessor to market the production for the mutual benefit of 
the lessee and the lessor, then ONRR shall require that the 
transportation allowance be determined in accordance with paragraph (b) 
of this section. When ONRR determines that the value of the 
transportation may be unreasonable, ONRR will notify the lessee and 
give the lessee an opportunity to provide written information 
justifying the lessee's transportation costs.
    (4) Where the lessee's payments for transportation under an arm's-
length contract are not based on a dollar-per-unit basis, the lessee 
shall convert whatever consideration is paid to a dollar value 
equivalent for the purposes of this section.
    (b) Non-arm's-length or no contract. (1) If a lessee has a non-
arm's-length contract or has no contract, including those situations 
where the lessee performs transportation services for itself, the 
transportation allowance will be based upon the lessee's reasonable 
actual costs. All transportation allowances deducted under a non-arm's-
length or no contract situation are subject to monitoring, review, 
audit, and possible future adjustment. Prior ONRR approval of 
transportation allowances is not required for non-arm's-length or no 
contract situations. However, before any estimated or actual deduction 
may be taken, the lessee must submit a completed form ONRR-4293 in 
accordance with paragraph (c)(2) of this section. A transportation 
allowance may be claimed retroactively for a period of not more than 3 
months prior to the first day of the month that form ONRR-4293 is filed 
with ONRR, unless ONRR approves a longer period upon a showing of good 
cause by the lessee. ONRR will monitor the allowance deductions to 
ensure that deductions are reasonable and allowable. When necessary or 
appropriate, ONRR may direct a lessee to modify its estimated or actual 
transportation allowance deduction.
    (2) The transportation allowance for non-arm's-length or no 
contract situations shall be based upon the lessee's actual costs for 
transportation during the reporting period, including operating and 
maintenance expenses, overhead, and either depreciation and a return on 
undepreciated capital investment in accordance with paragraph 
(b)(2)(iv)(A) of this section, or a cost equal to the depreciable 
investment in the transportation system multiplied by the rate of 
return in accordance with paragraph (b)(2)(iv)(B) of this section. 
Allowable capital costs are generally those for depreciable fixed 
assets (including costs of delivery and installation of capital 
equipment) which are an integral part of the transportation system.
    (i) Allowable operating expenses include: Operations supervision 
and engineering; operations labor; fuel; utilities; materials; ad 
valorem property taxes; rent; supplies; and any other directly 
allocable and attributable operating expense which the lessee can 
document.
    (ii) Allowable maintenance expenses include: Maintenance of the 
transportation system; maintenance of equipment; maintenance labor; and 
other directly allocable and attributable maintenance expenses which 
the lessee can document.
    (iii) Overhead attributable and allocable to the operation and 
maintenance of the transportation system is an allowable expense. State 
and Federal income taxes and severance taxes and other fees, including 
royalties, are not allowable expenses.
    (iv) A lessee may use either paragraph (b)(2)(iv)(A) or (B) of this 
section. After a lessee has elected to use either method for a 
transportation system, the lessee may not later elect to change to the 
other alternative without approval of ONRR.
    (A) To compute depreciation, the lessee may elect to use either a 
straight-line depreciation method based on the life of equipment or on 
the life of the reserves which the transportation system services, 
whichever is appropriate, or a unit of production method. After an 
election is made, the lessee may not change methods without ONRR 
approval. A change in ownership of a transportation system shall not 
alter the depreciation schedule established by the original 
transporter/lessee for purposes of the allowance calculation. With or 
without a change in ownership, a transportation system shall be 
depreciated only once. Equipment shall not be depreciated below a 
reasonable salvage value.
    (B) ONRR shall allow as a cost an amount equal to the allowable 
capital investment in the transportation system multiplied by the rate 
of return determined pursuant to paragraph (b)(2)(B)(v) of this 
section. No allowance shall be provided for depreciation. This 
alternative shall apply only to transportation facilities first placed 
in service or acquired after March 1, 1989.

[[Page 36988]]

    (v) The rate of return shall be the industrial rate associated with 
Standard and Poor's BBB rating. The rate of return shall be the monthly 
average as published in Standard and Poor's Bond Guide for the first 
month of the reporting period of which the allowance is applicable and 
shall be effective during the reporting period. The rate shall be 
redetermined at the beginning of each subsequent transportation 
allowance reporting period (which is determined pursuant to paragraph 
(c)(2) of this section).
    (3) A lessee may apply to ONRR for exception from the requirement 
that it compute actual costs in accordance with paragraphs (b)(1) and 
(2) of this section. ONRR will grant the exception only if the lessee 
has a rate for the transportation approved by a Federal agency for 
Indian leases. ONRR shall deny the exception request if it determines 
that the rate is excessive as compared to arm's-length transportation 
charges by systems, owned by the lessee or others, providing similar 
transportation services in that area. If there are no arm's-length 
transportation charges, ONRR shall deny the exception request if:
    (i) No Federal regulatory agency cost analysis exists and the 
Federal regulatory agency has declined to investigate pursuant to ONRR 
timely objections upon filing; and
    (ii) The rate significantly exceeds the lessee's actual costs for 
transportation as determined under this section.
    (c) Reporting requirements--(1) Arm's-length contracts. (i) With 
the exception of those transportation allowances specified in 
paragraphs (c)(1)(v) and (vi) of this section, the lessee shall submit 
page one of the initial form ONRR-4293 prior to, or at the same time 
as, the transportation allowance determined pursuant to an arm's-length 
contract is reported on form ONRR-4430, Solid Minerals Production and 
Royalty Report.
    (ii) The initial form ONRR-4293 shall be effective for a reporting 
period beginning the month that the lessee is first authorized to 
deduct a transportation allowance and shall continue until the end of 
the calendar year, or until the applicable contract or rate terminates 
or is modified or amended, whichever is earlier.
    (iii) After the initial reporting period and for succeeding 
reporting periods, lessees must submit page one of form ONRR-4293 
within 3 months after the end of the calendar year, or after the 
applicable contract or rate terminates or is modified or amended, 
whichever is earlier, unless ONRR approves a longer period (during 
which period the lessee shall continue to use the allowance from the 
previous reporting period). Lessees may request special reporting 
procedures in unique allowance reporting situations, such as those 
related to spot sales.
    (iv) ONRR may require that a lessee submit arm's-length 
transportation contracts, production agreements, operating agreements, 
and related documents. Documents shall be submitted within a reasonable 
time, as determined by ONRR.
    (v) Transportation allowances that are based on arm's-length 
contracts and which are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For the purposes of this section, only those allowances that have been 
approved by ONRR in writing shall qualify as being in effect at the 
time these regulations become effective.
    (vi) ONRR may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (2) Non-arm's-length or no contract. (i) With the exception of 
those transportation allowances specified in paragraphs (c)(2)(v) and 
(vii) of this section, the lessee shall submit an initial form ONRR-
4293 prior to, or at the same time as, the transportation allowance 
determined pursuant to a non-arm's-length contract or no contract 
situation is reported on form ONRR-4430, Solid Minerals Production and 
Royalty Report. The initial report may be based on estimated costs.
    (ii) The initial form ONRR-4293 shall be effective for a reporting 
period beginning the month that the lessee first is authorized to 
deduct a transportation allowance and shall continue until the end of 
the calendar year, or until the transportation under the non-arm's-
length contract or the no contract situation terminates, whichever is 
earlier.
    (iii) For calendar-year reporting periods succeeding the initial 
reporting period, the lessee shall submit a completed form ONRR-4293 
containing the actual costs for the previous reporting period. If the 
transportation is continuing, the lessee shall include on form ONRR-
4293 its estimated costs for the next calendar year. The estimated 
transportation allowance shall be based on the actual costs for the 
previous reporting period plus or minus any adjustments that are based 
on the lessee's knowledge of decreases or increases that will affect 
the allowance. form ONRR-4293 must be received by ONRR within 3 months 
after the end of the previous reporting period, unless ONRR approves a 
longer period (during which period the lessee shall continue to use the 
allowance from the previous reporting period).
    (iv) For new transportation facilities or arrangements, the 
lessee's initial form ONRR-4293 shall include estimates of the 
allowable transportation costs for the applicable period. Cost 
estimates shall be based upon the most recently available operations 
data for the transportation system, or, if such data are not available, 
the lessee shall use estimates based upon industry data for similar 
transportation systems.
    (v) Non-arm's-length contract or no contract-based transportation 
allowances that are in effect at the time these regulations become 
effective will be allowed to continue until such allowances terminate. 
For purposes of this section, only those allowances that have been 
approved by ONRR in writing shall qualify as being in effect at the 
time these regulations become effective.
    (vi) Upon request by ONRR, the lessee shall submit all data used to 
prepare its form ONRR-4293. The data shall be provided within a 
reasonable period of time, as determined by ONRR.
    (vii) ONRR may establish, in appropriate circumstances, reporting 
requirements that are different from the requirements of this section.
    (viii) If the lessee is authorized to use its Federal-agency-
approved rate as its transportation cost in accordance with paragraph 
(b)(3) of this section, it shall follow the reporting requirements of 
paragraph (c)(1) of this section.
    (3) ONRR may establish reporting dates for individual lessees 
different than those specified in this paragraph in order to provide 
more effective administration. Lessees will be notified as to any 
change in their reporting period.
    (4) Transportation allowances must be reported as a separate line 
item on form ONRR-4430, unless ONRR approves a different reporting 
procedure.
    (d) Interest assessments for incorrect or late reports and failure 
to report. (1) If a lessee deducts a transportation allowance on its 
form ONRR-4430 without complying with the requirements of this section, 
the lessee shall be liable for interest on the amount of such deduction 
until the requirements of this section are complied with. The lessee 
also shall repay the amount of any allowance which is disallowed by 
this section.
    (2) If a lessee erroneously reports a transportation allowance 
which results in an underpayment of royalties, interest shall be paid 
on the amount of that underpayment.

[[Page 36989]]

    (3) Interest required to be paid by this section shall be 
determined in accordance with Sec.  [thinsp]1218.202 of this chapter.
    (e) Adjustments. (1) If the actual transportation allowance is less 
than the amount the lessee has taken on form ONRR-4430 for each month 
during the allowance form reporting period, the lessee shall be 
required to pay additional royalties due plus interest, computed 
pursuant to Sec.  [thinsp]1218.202 of this chapter, retroactive to the 
first month the lessee is authorized to deduct a transportation 
allowance. If the actual transportation allowance is greater than the 
amount the lessee has estimated and taken during the reporting period, 
the lessee shall be entitled to a credit, without interest.
    (2) The lessee must submit a corrected form ONRR-4430 to reflect 
actual costs, together with any payment, in accordance with 
instructions provided by ONRR.
    (f) Other transportation cost determinations. The provisions of 
this section shall apply to determine transportation costs when 
establishing value using a net-back valuation procedure or any other 
procedure that requires deduction of transportation costs.


Sec.  [thinsp]1206.462   [Reserved]


Sec.  [thinsp]1206.463  In-situ and surface gasification and 
liquefaction operations.

    If an ad valorem Federal coal lease is developed by in-situ or 
surface gasification or liquefaction technology, the lessee shall 
propose the value of coal for royalty purposes to ONRR. ONRR will 
review the lessee's proposal and issue a value determination. The 
lessee may use its proposed value until ONRR issues a value 
determination.


Sec.  [thinsp]1206.464  Value enhancement of marketable coal.

    If, prior to use, sale, or other disposition, the lessee enhances 
the value of coal after the coal has been placed in marketable 
condition in accordance with Sec.  [thinsp]1206.456(h) of this subpart, 
the lessee shall notify ONRR that such processing is occurring or will 
occur. The value of that production shall be determined as follows:
    (a) A value established for the feedstock coal in marketable 
condition by application of the provisions of Sec.  
[thinsp]1206.456(c)(2)(i) through (iv) of this subpart; or,
    (b) In the event that a value cannot be established in accordance 
with paragraph (a) of this section, then the value of production will 
be determined in accordance with Sec.  [thinsp]1206.456(c)(2)(v) of 
this subpart and the value shall be the lessee's gross proceeds 
accruing from the disposition of the enhanced product, reduced by ONRR-
approved processing costs and procedures including a rate of return on 
investment equal to two times the Standard and Poor's BBB bond rate 
applicable under Sec.  [thinsp]1206.458(b)(2)(v) of this subpart.

[FR Doc. 2017-16571 Filed 8-4-17; 8:45 am]
 BILLING CODE 4335-30-P