Unintentional Misconduct and Standardless Discretion: The Department of Interior’s New Rules for Valuing Oil, Gas and Coal

The Office of Natural Resources Revenue (ONRR) within the Department of the Interior issued new royalty valuation rules on July 1, 2016. Although the goal of the regulations is to simplify the calculation of royalties on federal oil, gas and coal, the 65 pages of rules please no one. Under a new definition for “misconduct,” normally considered to require some degree of intent, misconduct now “means any failure to perform a duty owed to the United States under a statute, regulation, or lease, or unlawful or improper behavior, regardless of the mental state of the lessee or any individual employed by or associated with the lessee.” 30 C.F.R. § 1206.20. Although ONRR can pursue civil penalties only if the misconduct is intentional, in the case of unintentional misconduct connected with a royalty valuation, such as a simple reporting error, ONRR can impose its own valuation.

ONRR has also added a controversial default provision allowing ONRR to substitute its own oil valuation for that reported by a lessee based on actual arm’s-length contracts. Decried by industry as “standardless” ONRR discretion and “second-guessing of arm’s-length contracts,” the provision lacks specific criteria for determining what is a reasonable valuation and gives ONRR the power to impose its own valuation based on “any information we deem relevant.” 30 C.F.R. §§ 1206.101 and 1206.105. Many companies are concerned that the lack of specific criteria for valuation will create uncertainty and act to discourage development of federal minerals.

While industry is not pleased with the new rules, neither is the environmental community, which submitted over 190,000 petition signatures during the public comment period urging the government to “keep it in the ground.” ONRR declined to act, however, stating that a decision to halt federal fossil fuel production was beyond the scope of this rulemaking.

The Final Rule, which takes effect on January 1, 2017, may be found here.

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Drafting Oil and Gas Royalty Provisions; KISS- “Keep it Simple, Stupid!”

The KISS principle that systems perform best with simple rather than complex designscan apply in the world of legal drafting. This lesson was recently learned by lawyers who drafted a complex “work-around” to avoid a judicial interpretation of standard oil and gas lease royalty language on whether post-production costs should be included in the royalty calculation. In Chesapeake Exploration, L.L.C. v. Hyder, 2015 WL 3653446, 58 Tex. Sup. Ct. J. 1182, the Texas Supreme Court rejected the “work-around” language, reaffirming its prior holding that standard gas royalty language has a particular meaning and that attempts to add language to “clarify” the parties intent to alter the language will be deemed “surplusage” and given no effect.

June 12, 2015, Texas Supreme Court addressed whether an overriding royalty (“ORR”) with “cost-free” language should bear postproduction costs. The lease included three royalty provisions: (1) a 25% royalty of the market value at the well of all oil and liquid hydrocarbons; (2) a 25% royalty “of the price actually received by Lessee” on all gas produced and sold or used; and (3) “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent (5%) of gross production” from directional wells drilled on the leased lands but bottomed on adjacent lands. The gas royalty provision also included additional language that the royalty is to be “free and clear of all production and post production costs and expenses” and listed various examples. The lease contained two other relevant provisions: (1) that the lessor has the continuing right to take the royalty in kind and (2) a disclaimer that “Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and provisions of this Lease.”

While the ultimate issue before the Court was the ORR calculation, the Court took the opportunity to weigh in on the gas royalty provision. The Court noted that the royalty provision’s “price actually received” language, which generally creates a “proceeds lease” based on the price-received for calculating royalty payments, was adequate to exempt the lessors from bearing post-production costs and that a royalty does not bear production costs. Therefore, the Court held that the additional language that the royalty “is free and clear of all production and post production costs and expenses” was either meaningless, merely emphasized the cost-free nature of the gas royalty, or “surplusage.” The import of the Court’s dicta (discussion of issues not decided) is that language in a royalty provision is given specific meaning and will be interpreted based on the language that creates the royalty and efforts to clarify the royalty with additional language may be disregarded entirely.

The real issue before the Court was whether the “cost-free” language in the ORR exempted the Hyders from paying their proportionate share of post-production costs. The parties agreed that an ORR is like a landowner’s royalty, i.e., free of production costs but bears post-production costs unless agreed otherwise.

The Hyders argued that the term “cost-free” could only apply to post-production costs because the ORR is already free of production costs. The Court, however, was not persuaded because, like the gas royalty, the term “cost-free” may simply emphasize that the ORR is free of production costs. Chesapeake argued that “cost-free” was a synonym for overriding royalty, citing numerous lease provisions from other cases to support its contention that the phrase “cost-free” could not refer to post-production costs.

The Court held that because the ORR was drafted as an “in kind” royalty to be paid on gross production with the option to take the royalty in cash, the royalty must be calculated on the volume of gas produced at the wellhead. If taken in kind, the Hyders would receive their share of gas free of post-production costs. Accordingly, if the Hyders elected instead to take their ORR in cash, the term “cost-free” must include post-production costs.

While having already resolved the question before it, the Court nonetheless chose to address the Hyders’ last argument that the lease’s disclaimer of any application of Heritage Resources showed an intent that the ORR be free of post-production costs. Heritage Resources involved a gas royalty calculated on “the market value at the well” but also added that there would be “no deductions from the value of the Lessor’s royalty by reason of any” post-production costs. The Heritage Court held that because “market value at the well” is already net of reasonable marketing costs, additional language regarding “no deductions” for post-production costs does not change the meaning of the royalty clause and can only be said to be “surplusage.”

The Court noted that Heritage Resources does not hold that a royalty cannot be free of post-production costs. Rather, Heritage Resources stands for the proposition that a lease’s effect is governed by a fair reading of its text. Accordingly, a disclaimer of Heritage Resources could not free a royalty of post-production costs when the text of the lease did not clearly do so. Thus, the primary take-away point of the Hyder case is that drafters of royalty provisions must be precise in their word choice, ecause courts will construe royalty provisions as drafted according to established industry custom and are not inclined to look to clarifying language that is redundant, emphasizes, or otherwise conflicts with the royalty provisions.

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BLM Begins Regulatory Process to Increase Oil and Gas Royalties, Rentals, Minimum Bids, Bonding and Penalties

As promised by Secretary Jewell in March, see previous post, BLM is initiating a rulemaking process-- Announcement of Proposed Rulemaking (ANPR)-- to “solicit public comments and suggestions that may be used to update the BLM’s regulations related to royalty rates, annual rental payments, minimum acceptable bids, bonding requirements, and civil penalty assessments for Federal onshore oil and gas leases.” The comment period will close on June 5, 2015. At the end of the ANPR, the BLM poses a series of questions and readers will want to review the questions carefully for how best to respond to the ANPR. http://www.gpo.gov/fdsys/pkg/FR-2015-04-21/pdf/2015-09033.pdf

The BLM cites three principle reasons that compel their consideration of increasing the cost of developing federal oil and gas. 1) Three GAO reports, two in 2008 and the most recent in 2011, that have questioned whether BLM is obtaining an appropriate royalty for the development of federal oil and gas; 2) the finding that none of the regulatory rates have been adjusted for inflation or changed since they were put in place several decades ago; and 3) in order to ensure a fair return to the taxpayer. This effort will also further three initiatives that the Administration has been pursuing – higher royalties, the concept of “use it or lose it” for federal leases and an emphasis on enforcement and inspection by increasing bonding and penalties to ensure that companies are incentivized to do the right thing.

The current royalty rate is 12.5% and any change in the rate will be for leases issued in the future not existing leases. The proposed royalty changes will not apply to Tribal or Allotted leases issued under the Indian Mineral Leasing Act. BLM admits that adjusting the royalty rate is difficult, it references several studies it has done to get at the question, provides a chart of state royalty rates currently being used in states with federal oil and gas and considers that complex questions of economics are involved. “The BLM acknowledges that current oil and gas prices are low, relative to the average price over the past decade; however, recognizing the historic variability of those process, the BLM would be interested in information on the impacts of any royalty rate change at a range of oil and gas prices.”

In this ANPR, the BLM is also considering whether to raise the minimum acceptable bid for competitive leases; the bid amount has not been changed since enacted in 1987. For non-competitive leases the minimum bid is set by statute and can’t be changed by rule. As to increasing rental rates, “the BLM has not increased the rental rates ($1.50-2.00) since they were initially set in 1987 . . .” Similarly, as to bonding BLM has not “increased the minimum bond since 1960” and wants to consider whether the individual/lease, statewide and nationwide bond amounts are adequate to protect the taxpayer from the costs of reclamation. Finally, BLM, in response to a critical Inspector General report, wants to examine the regulatory caps on the penalties BLM can assess for trespass and other violations of law. Each of these proposed changes has the potential to add considerable cost to the already high cost of doing business on federal lands.

The breadth of the proposal is sure to attract the attention of Congress. Indeed, BLM recognizes that before it can change the minimum bid, the Mineral Leasing Act requires the Secretary to provide 90 days’ notice to the House Natural Resources Committee and the Senate Energy Committee. 30 U.S.C. 226(b)(1)(B). Congress and industry will all need to pay close attention to this process. In particular, it is important for the industry to respond to the questions that BLM has raised as well as the questions they have failed to raise in the ANPR by June 5, 2015.

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