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

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URL: https://www.frixlaw.com/law-library/documents/fr%3A2017-16571

## Record

- **Collection:** Federal Register
- **Document type:** Rule
- **Published:** August 7, 2017
- **Citation:** 82 FR 36934

## Text

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.

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

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.

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

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)

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,

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.

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.

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

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

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

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 reinstated

42,700
42,700
42,700

POP contracts processing allowance exceptions of 66
2/3
percent reinstated

9,470,000
9,470,000
9,470,000

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.

2015 MMBtu
volume
(non-rounded)

Royalty decrease
($)

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
(rounded to the
nearest gallon)

Royalty decrease ($)

Low
($0.00 cents)

Mid
($0.15)

High
($0.03)

NARM volume
66,911,096
$0
$1,003,666
$2,007,333

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] × 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.

Time burden
per line
reported
(min)

Estimated lines
reported using
index option
(50%)

Annual
burden
hours

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.

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
allowances

70%
30%

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 ×
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.

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 × 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 × 1.4). Using this labor cost per hour, we estimate the annual administrative cost to industry would be approximately:

Annual
burden
hours per
company

Industry
labor
cost/hour

Companies
reporting
eligible
leases

Estimated
cost to
industry

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 ×
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 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 ×
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'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

Line loss
%

Royalty
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

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

Line loss
%

Royalty
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

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 reinstated
$87,000
($55,400)
($30,900)
($744)

Processing allowance 66
2/3
% limitation exceptions reinstated

$42,700
($29,900)
($12,500)
($274)

POP contracts' processing allowance exceptions of 66
2/3
% limitation reinstated

$9,470,000
($6,640,000)
($2,770,000)
($60,700)

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 reinstated
$0
$0
$0
$0

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

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 § 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 §

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Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/fr%3A2017-16571. Public record. Not legal advice.