WHAT CONGRESS JUST DID TO HELP FILL THE HELIUM GAP - SOMETHING TO CELEBRATE (EVEN WITHOUT BALLOONS)

While most people were watching whether the Land and Water Conservation Fund would be reauthorized in the John D. Dingell, Jr. Conservation Management, and Recreation Act (Dingell Act), a few of us were hoping the long-sought “helium fix” would at last make it across the finish line. When the President signed the Dingell Act on March 12, 2019, Section 1109, “Maintenance of Federal Mineral Leases Based on Extraction of Helium,” was included. What is the helium “fix” and why should we care about helium anyway?

Most people are familiar with helium from buying party balloons. But that is a minor (1%) part of its use. Helium plays a much more important role in space and aerospace applications, fiber optics, airbags, high-speed internet and medicine. MRI imaging depends on the ability of helium to hold a temperature of -269 degrees. In May 2018, pursuant to Executive Order 13817, the Trump administration identified helium as one of 35 minerals deemed critical to U.S. national security and the economy. 83 Fed. Reg. 2395 (May 18, 2018). And, this year, the media is highlighting a helium shortage that is closing 45 Party City stores and sending helium prices sky-high.

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Unearthing Squandered Potential in Venezuela’s Oil Industry: A Tripartite Contractual Approach

Venezuela is reeling from a multitude of woes. Vast swathes of the population have fled to neighboring countries as a humanitarian crisis flares out of control. The Venezuelan oil industry – the economy’s frail linchpin – has not escaped the morass. PdVSA, the state-owned oil company, is crippled by chronic operating mismanagement and resource nationalism.

However, political pressure is mounting for the country’s corruption-smeared leader, Nicolás Maduro. Russo-Cuban good-will and a pseudo-loyal military provide only a slim reed for him to lean on. Furthermore, Juan Guiadó – the constitutionally recognized interim president – has galvanized popular support for a democratic re-boot in Venezuela.

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“All of the Above Energy”/ “Energy Dominance”: The Courts Strike Back on Climate Change

Although the Obama and Trump administrations differ markedly on climate change and energy policy, their oil and gas decisions are being similarly faulted by federal courts. President Obama had an “all of the above” energy policy that included the development of oil and gas but took addressing climate change as a serious obligation. President Trump has by executive order (EO 13783), agency policies (Secretarial Order 3360) and rulemakings rejected Obama climate change policies to support an “energy dominance” energy policy.

In March 2019, two federal courts considered two different phases of the Bureau of Land Management’s (BLM) oil and gas process—leasing and development—and found BLM’s National Environmental Policy Act (NEPA) analysis faulty for failing to adequately consider greenhouse gas (GHG) emissions and climate change impacts. WildEarth Guardians v. Zinke (D.D.C., March 13, 2019) (WEG) and Citizens for a Healthy Community v. BLM (D. Colo., March 27, 2019) (Citizens). Oil and gas lease holders in Wyoming and an oil and gas development in Colorado have been stymied as the courts direct BLM to improve its analysis of climate change impacts. The WEG court refused to vacate the leases, but on remand directed BLM to complete a new analysis before allowing development on existing leases or any new leasing. Although the industry has asked the administration to appeal the WEG decision, the administration’s next move is not clear. The Citizens court has asked for additional briefing on a remedy.

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Martinez v. COGCC: Colorado Supreme Court Rejects Adverse Impacts Pre-Condition

On January 14, 2019, the Colorado Supreme Court reached a decision in COGCC v. Martinez, ending more than five years of litigation between seven youth activists from Boulder-based Earth Guardians and the Colorado Oil and Gas Conservation Commission (“COGCC”). The Court held that the COGCC appropriately exercised its agency discretion when it declined to undertake a rulemaking that would have conditioned approval of applications for oil and gas drilling permits on a conditional finding of no adverse impacts to health, safety, or the environment.

The facts of the highly publicized case are well known. In 2013, Earth Guardians petitioned the COGCC to promulgate a rule requiring that COGCC withhold issuance of any new drilling permits “unless the best available science demonstrates, and an independent, third party organization confirms, that drilling can occur in a manner that does not cumulatively, with other actions, impair Colorado’s atmosphere, water, wildlife, and land resources, does not adversely impact human health, and does not contribute to climate change.” COGCC declined to undertake the proposed rule-making, finding, inter alia, that the proposed rule was beyond COGCC’s limited statutory scope. The petitioners appealed to district court, which affirmed COGCC’s denial of the petition.

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Wyoming Supreme Court Punts on Potential BLM “First in Time, First in Right” Interpretation of Competing Mineral Developers

A recent case before the Wyoming Supreme Court failed to clarify what, if any, remedies are available to conflicting developers of federal mineral rights on overlapping lands. Rather, the Court’s ruling in Berenergy Corporation v. BTU Western Resources, Inc.; School Creek Coal Resources, LLC; and Peabody Powder River Mining, LLC, and BTU Western Resources, Inc.; School Creek Coal Resources, LLC; and Peabody Powder River Mining, LLC v. Berenergy Corporation1 stated it could not decide the issue, while not so subtly asking the Secretary of the Interior and Bureau of Land Management (BLM), which could decide, to no longer “sit this one out.”

Berenergy Corporation (Berenergy) owned three oil and gas leases granted by the BLM. Berenergy originally filed for a declaratory judgment that the rights under its leases were superior to those under coal leases on overlapping lands that the BLM had issued later to affiliates of Peabody Energy Corporation (Peabody). Berenergy sought to prevent Peabody from shutting down Berenergy’s wells for fifteen to twenty years while Peabody mined areas in the overlapping land, and to prevent interference with Berenergy’s operations, including plans to water-flood oil-bearing formations covered in its leases.

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Interior Reins in the MBTA to Remove a “Domestic Energy Burden”

Mining, oil and gas, wind, solar and transmission companies who have struggled to comply with the Migratory Bird Treaty Act of 1918 (MBTA) received an early Christmas present from the U.S. Department of the Interior’s lawyer. On December 22, 2017, the Principal Deputy Solicitor issued a binding Memorandum Opinion, M-37050, to limit the reach of the MBTA to intentional, unlawful acts of hunting and poaching. In a 41-page legal analysis, the Solicitor concludes, “The text, history and purpose of the MBTA demonstrate that it is a law limited in relevant part to affirmative and purposeful actions, such as hunting and poaching, that reduce migratory birds and their nests and eggs, by killing or capturing, to human control. . . . Interpreting the MBTA to criminalize incidental takings raises serious due process concerns and is contrary to the fundamental principle that ambiguity in criminal statutes must be resolved in favor of defendants.” This action came in response to Executive Order 13783, Promoting Energy Independence and Economic Growth (March 28, 2017) and was a regulatory review specifically identified by Interior in the “Final Report: Review of the Department of the Interior Actions that Potentially Burden Domestic Energy,” (October 24, 2017) at pp. 32-33.

Why was addressing the MBTA a priority for the Trump Administration? For one, it was a “midnight rule” exemplifying the Obama-era regulation of the energy industry. On January 10, 2017, as the Obama Administration was drawing to a close, its Solicitor issued a legal analysis determining that the MBTA should be interpreted to cover “incidental take” (“apply broadly to any activity”) of migratory birds, and the U.S. Fish and Wildlife Service (USFWS) issued an implementing guidance document. “Incidental take” liability means that otherwise lawful actions like constructing a wind turbine, maintaining an oil and gas wastewater facility or constructing a transmission line could result in prosecutable take under the MBTA.1

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The Surge in DUC Wells Begs the Question: How Long Can a DUC Well Hold a Lease?

Just over a year ago, the U.S. Energy Information Administration (“EIA”) began including a supplement to its Drilling Productivity Report that contains monthly estimates of the number of drilled but uncompleted (“DUC”) wells in seven key oil and gas producing basins (the Anadarko, Appalachia, Bakken, Eagle Ford, Niobrara, Haynesville, and Permian basins). Prior DUC well inventory numbers made headlines starting in late 2015 (see here and here). The most recent EIA Drilling Productivity Report 1 shows that while DUC well inventory began to subside in the latter part of 2016 and first part of 2017, there has been a recent surge - largely led by significant growth in the Permian basin.

The economic impact of completing and bringing these wells online could create a surge in oil supply and destabilize recent crude oil price gains. Aside from the potential implications to crude oil prices, one consideration that remains top of mind for operators with DUC wells on maturing oil and gas leases is whether, or for how long, a DUC well can hold a lease.

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Russia Fails to Defeat Fracking

Gazprom, Russia’s government owned natural gas company, has for decades supplied many Eastern European countries with most or all of their natural gas. It has also had a habit of using its dominant market position to bully its customers into paying more, often by cutting off natural gas supplies needed for heating in midwinter. Gazprom reduced or completely stopped flows of gas to Ukraine in 2006 and 2008, to 18 European countries in 2009, to Ukraine and Poland in 2014, and to Ukraine, Bulgaria, Romania, Slovenia and Bosnia in 2015.

Several years ago Russia and Gazprom identified U.S. hydraulic fracturing technology (fracking) as a threat to Gazprom’s market share, especially its near monopoly over supplying gas to Eastern Europe. The Russians realized that fracking technology had the potential to undermine their position by increasing the development of natural gas that would compete on the open market with Russian gas. In an attempt to address this threat, Russia turned to RT (formerly Russia Today), Russia’s government controlled television network aimed at influencing audiences outside of Russia.

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IBLA Resolves Procedural Question for Review of Lease Suspension Decisions

Most decisions of the Bureau of Land Management (BLM) are appealable to the Interior Board of Land Appeals (IBLA). However, some decisions must first be reviewed by the applicable BLM State Director. Parties who wish to appeal from decisions issued under the oil and gas operating regulations (43 C.F.R. Part 3160) and unitization regulations (43 C.F.R. Part 3180) must first seek State Director review before appealing to the IBLA.

Until recently, it was unclear whether a decision granting, denying or lifting a suspension of a federal oil and gas lease was a decision issued under the Part 3160 regulations, and therefore subject to State Director review, or was a decision issued under the Part 3100 regulations appealable directly to the IBLA. The reason for this uncertainty was that regulations pertaining to suspensions of leases are found in both Part 3160 (43 C.F.R. §3165.1) and Part 3100 (43 C.F.R. § 3103.4-4). Consequently, in the past, if a suspension request was denied by the BLM, we advised clients to file both a State Director review request and a provisional notice of appeal with the IBLA. Of course, the duplicate processes added cost and time to the appeal. In their responses to such provisional notices of appeal, the solicitor’s office generally took the position that such decisions should first be reviewed by the State Director. Now there is a recent decision of the IBLA that clarifies that decisions challenging a BLM suspension decision should first be reviewed by the State Director under the State Director review regulations.

In Southern Utah Wilderness Alliance, 190 IBLA 152 (2017), the IBLA addressed the ambiguity as to the proper appeal route from suspension decisions. It acknowledged that suspsensions are addressed in both parts of the regulations but noted that the regulation at § 3165.1(b) directs the authorized officer to act on suspension applications filed under § 3103.4-4, so that the decision-making authority is more clearly placed in the Part 3160 regulations. The Board also noted that, historically, when the U.S. Geological Survey (USGS) managed operations on federal leases, suspension decisions were first appealable to the Director of the USGS and then to the IBLA. Finally, the IBLA cited to a few of its earlier decisions which, although not directly addressing the question of whether suspension decisions should first be reviewed by the State Director, at least assumed that was the proper route. With the Southern Utah Wilderness Alliance decision, it is now clear that review of any BLM decision granting or denying a suspension of an oil and gas lease must first be reviewed by the State Director under the regulation at § 3165.3(b).

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The Battle over Local Control Heats up Again as Thornton’s Oil and Gas Regulations Challenged in Court

Six weeks following the City of Thornton’s adoption of strict new regulations on oil and gas operations, the Colorado Oil and Gas Association (“COGA”) and the American Petroleum Institute (“API”) have filed suit, in what looks to be just the latest clash in Colorado’s struggle over who manages oil and gas in the state – the Colorado Oil and Gas Conservation Commission (“COGCC”) or cities and towns?

In August, after what COGA described as “an extremely limited stakeholder process,” Thornton’s City Council adopted Ordinance No. 3477 by a 7-2 vote. The ordinance provides for much stricter standards than the rules of the COGCC. Some of the differences are highlighted below:

   Thornton's Ordinance COGCC Rules
Setback from Buildings/Lots Well pad must be at least 750 feet from existing or planned buildings and existing or platted residential lots (Section 18-881.(a)(1), (2)) Well must be at least 500 feet from a Building Unit (Rule 604.a.(1))
Setback from Water Bodies Well pad must be at least 500 feet from the ordinary High Water Mark (HWM) or the edge of the bank of any irrigation or lateral ditch (Section 18-881.(a)(3)) Setbacks only required for Drilling, Completion, Production and Storage Operations within Public Water System Surface Water Supply Areas (Rule 317B)
Surface Disturbance Multiple wells proposed by Operator must be located on a multi-well pad
(Section 18-881.(b)(1))
Operators must consolidate wells on multi-well pads only in Designated Setback Locations and only where technologically feasible and economically practicable (Rule 604.c.(2)E.i.)
Liability Insurance Operator must maintain general liability insurance of $5 million per occurrence (Section 18-881.(y)) Operator must maintain general liability insurance of $1 million per occurrence (Rule 708)
Flowlines  Abandoned flowlines must be removed (Section 18-881.(c)(1))  Flowlines may be abandoned in place if disconnected, buried, and permanently sealed (Rule 1103)

 

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Standing to Challenge Decisions Approving Federal Units or Suspending Federal Leases

Non-governmental organizations that oppose oil and gas development have in the last few years begun to challenge not only Bureau of Land Management (BLM) decisions authorizing oil and gas drilling operations but also BLM decisions that could have the effect of continuing leases in effect that might otherwise expire. In two recent decisions, the Interior Board of Land Appeals (IBLA) reiterated its position that, in order to seek State Director review of a decision or to appeal a decision to the IBLA, the appellant must demonstrate that the “legally cognizable interests” of it or its members will be adversely affected by the decision under review. Southern Utah Wilderness Alliance, 190 IBLA 152 (2017) (SUWA); Citizens of Huerfano County, 190 IBLA 253 (2017) (Huerfano).

Legally cognizable interests can include cultural, recreational and aesthetic use and enjoyment of the lands. But there must be a causal relationship between the alleged injury to those interests and the BLM decision under review. In addition, the threat of injury must be real and immediate. In SUWA, the appellant challenged a BLM decision suspending leases committed to the Deseret Unit in the Uintah Basin. BLM granted the suspension because its approval of the drilling permit (APD) for the unit obligation well would be delayed for several months while analysis of the proposal under the National Environmental Policy Act (NEPA) was prepared. SUWA asserted that the suspension was improperly granted because the unit operator had allegedly delayed in developing the leases, its application was not supported by sufficient information, and the BLM should have prepared an environmental assessment or environmental impact statement on the suspsension application. The IBLA did not address the substance of SUWA’s allegations because it found that SUWA had failed to demonstrate that its members’ health, recreational, spiritual, educational, aesthetic and other interests would be directly harmed by BLM’s decision to approve the suspension. The Board concluded that SUWA’s interests would be harmed only if oil and gas development occurred (i.e., if the APD was approved). The suspension of the leases did not result in “real and immediate” harm to SUWA’s interests so there was no causal link between the alleged injury and the BLM decision to suspend the lease. Any injury to SUWA which might occur was contingent on a future decision to approve drilling. Therefore, the IBLA upheld the State Director’s decision dismissing SUWA’s State Director review request for lack of standing.

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Extension of Federal Oil and Gas Leases

Operators who do not regularly operate on federal lands may be surprised to discover that, unlike the typical private lands oil and gas lease, a federal lease does not contain a drilling operations clause that would extend the lease beyond the expiration of its primary term while drilling operations are being conducted. A recent decision of the Interior Board of Land Appeals (IBLA) drives home the importance of understanding exactly what facts are sufficient to extend a federal lease.

In Coastal Petroleum Company, 190 IBLA 347 (July 25, 2017), the IBLA upheld a decision of the Montana State Office of the Bureau of Land Management (BLM) which concluded that a lease had terminated at the end of its primary term because the lessee had not established that the well it had drilled and completed was capable of producing gas in paying quantities. Coastal’s lease would expire October 31, 2012. According to the decision, a well was spud prior to that date, the well was fracture treated on September 14, 2012, Coastal pulled two gas samples and determined that the well had good pressure and was able to flow on October 16, 2012, and Coastal received the gas analysis report on October 29, 2012. Based on these operations, Coastal concluded that at least two formations on the structure contained gas and that the well was capable of producing in paying quantities. But the BLM concluded that, without a flow test, BLM was unable to determine whether the amount of production would be of sufficient value to exceed operating costs; i.e., production in paying quantities. The IBLA agreed and noted that the burden is on the lessee to establish that a lease has been extended by a well capable of producing in paying quantities. The lesson for federal lessees is to plan operations that are intended to extend an expiring lease so that the well is completed for production and flow tested prior to the expiration date.

Another cautionary lesson from the Coastal decision is the need for a contingency plan in the event a well drilled near the end of the primary terms may not be completed as capable of producing in provable paying quantities prior to that date. Coastal argued in the alternative before the IBLA that it was engaged in testing and completing operations at the expiration of the primary term and so was entitled to a two-year extension of the lease under the "drilling over” provision of 30 U.S.C. §226(e). Coastal had not raised this argument in its request for State Director review of the BLM Field Office decision that the lease had terminated. It is not clear from the facts whether Coastal was actually conducting operations that would qualify as testing or completing under the regulation (43 C.F.R. §3100.0-5(g)) or whether Coastal had timely tendered the 11th year rental which is necessary in order to earn the drilling over extension. Instead, the IBLA refused to consider the argument at all because Coastal had not raised it before the State Director. The IBLA cited prior cases which establish that the Board will not consider issues raised for the first time on appeal except in extraordinary circumstances. The Coastal case appears to be a situation that easily could have been avoided by timing the drilling, completing and testing operations on the well to continue at the expiration of the primary term and by payment of the 11th year rental.

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Colorado Supreme Court upholds retroactive tax assessment against oil and gas lessee

On June 19, 2017, the Colorado Supreme Court ruled against the petition of Kinder Morgan CO2 Co., LP -- the operator of oil and gas leaseholds -- disputing the Montezuma County Assessor's 2009 corrective tax assessment on leaseholds for the prior tax year which resulted in a retroactive assessment of over $2 million in property taxes. Kinder Morgan CO2 Co., L.P. v. Montezuma County Board of Commissioners; Colorado Board of Assessment Appeals; and Colorado Property Tax Administrator. The Board of Assessment Appeals upheld the retroactive assessment finding that Kinder Morgan had underreported the selling price of its production by over-deducting its costs.

Oil and gas leaseholds and lands are valued under Colorado statutes, Article 7 of Title 39, pursuant to which a lessee must submit an annual statement (reporting the volume and price of product sold at the wellhead), following which the county assessor determines property value and tax liability. See § 39-7-101 -103(2). Because the sale of unprocessed oil or gas rarely occurs at the wellhead, an operator usually estimates the wellhead selling price, deducting costs for, e.g. gathering, processing, and transporting the extracted material – called the “netback” method of calculating the wellhead price. See § 39-7-101(1)(d) (“The net taxable revenues shall be equal to the gross lease revenues, minus deductions for gathering, transportation, manufacturing, and processing costs borne by the taxpayer pursuant to guidelines established by the [Property Tax Administrator].”). The resulting price for purposes of § 39-7-101(1)(d) is an estimate. An “operator’s netback calculation depends on whether the operator contracts with a related or an unrelated party to perform these gathering, processing, and transportation services. If the operator enters into a bona fide, arm’s-length transaction with an unrelated party to perform these services, then the operator may deduct the full amount paid for these services from its final, downstream sales price in its netback calculation (the ‘unrelated-parties netback method’). See 3 Div. of Prop. Taxation, Colo. Dep’t of Local Affairs, Assessor’s Reference Library: Real Property Valuation Manual (ARL) 6.35–6.36 (Rev. Jan. 2017).” Accordingly, if, as here, “the operator instead enters into a transaction with a related party . . . then it may deduct only a portion of the amount paid for these services (the ‘related-parties netback method’). 3 ARL 6.39–6.41.” (Emphasis added.)

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Paris Agreement Exit: Who Holds the Real Power?

President Trump announced on June 1 that the United States is withdrawing from the Paris Agreement. The announcement follows months of uncertainty about whether President Trump would fulfill his campaign pledge to withdraw U.S. participation in the deal (which was signed by 195 countries with only two countries in opposition--Nicaragua (because it wasn’t stringent enough) and Syria).

According to the President, the decision is necessary to protect the U.S. economy from burdensome emissions restrictions and foreign interference in U.S. energy policy:

In order to fulfill my solemn duty to protect America and its citizens, the United States will withdraw from the Paris climate accord . . .[s]o we're getting out, but we will start to negotiate, and we will see whether we can make a deal that’s fair.

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Earthquakes: State Regulation of O&G Injection Wells Is OK Oklahoma Judge Dismisses Federal Lawsuit on Jurisdictional Grounds

On Tuesday, April 4, 2017, Judge Stephen P. Friot, United States District Court for the Western District of Oklahoma, dismissed a nationally significant lawsuit brought over earthquakes linked to oil and gas wastewater injection wells on jurisdictional grounds.  See Sierra Club v. Chesapeake Operating, LLC, et al., No. CIV-16-134-F (W.D. Okla., Order dated 4/4/2017) (unpublished), The court deferred to the expertise of the Oklahoma Corporation Commission (“OCC”), the state body governing wastewater injection wells in Oklahoma. Citing the actions and capability of the OCC, Friot concluded:

Every night, more than a million Oklahomans go to bed with reason to wonder whether they will be awakened by the muffled boom which precedes, by an instant, the shaking of the ground under their homes. Responding to earthquake activity is serious business, requiring serious regulatory action. The record in this case plainly demonstrates that the Oklahoma Corporation Commission has responded energetically to that challenge. Of equal importance, it is plain that the Oklahoma Corporate Commission has brought to bear a level of technical expertise that this court could not hope to match.  The challenge of determining what it will take to meaningfully reduce seismic activity in and near the producing areas of Oklahoma is not an exact science, but it is no longer one of the black arts.  This court is ill-equipped to outperform the Oklahoma Corporation Commission in advancing that science and putting the growing body of technical knowledge to work in the service of rational regulation.

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Nonconsenting Owner in a Colorado Oil and Gas Well Must First Pursue Claim for Payment of Proceeds of Production at COGCC – not District Court

A recent Colorado Court of Appeals decision involves two parts of the statutes regarding the Colorado Oil and Gas Conservation Commission (Commission):  the pooling statute and the statute regarding payment of proceeds of production.  In Grant Brothers Ranch, LLC v. Antero Resources Piceance Corporation, ___ P.3d __ (2016), 2016 COA 178, the court held that the nonconsenting owner was required to exhaust its administrative remedies by bringing its claim at the Commission, and that the nonconsenting owner’s claim brought in district court should have been dismissed without prejudice.

The Commission established two drilling and spacing units to produce oil and gas in Garfield County.  Antero Resources Piceance Corporation (Antero) offered to lease the mineral interest owned by Grant Brothers Ranch, LLC (Grant Brothers) in the units.  Grant Brothers did not lease its interest and also refused Antero’s offers for Grant Brothers to participate in the wells.  After Antero’s requests, the Commission entered orders pooling all nonconsenting interests in the units. 

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CAUTION: New Federal Oil And Gas Royalty Regulations Take Effect January 1, 2017

The U.S. Department of Interior recently announced new regulations (effective January 1, 2017) governing how federal royalties on oil and gas produced from federal leases are to be calculated. These regulations make some significant changes on how lessees are to value the production of natural gas from federal leases for the purposes of determining federal royalties. Some notable changes, with a focus on natural gas, are briefly addressed below, but the regulations should be viewed in their entirety in light of the specific marketing, transportation and processing circumstances involved.

Valuation of Unprocessed Gas

For non-arm’s length sales of unprocessed gas, the Office of Natural Resources Revenue (ONRR) is eliminating the valuation “benchmarks.” Instead, where a lessee’s sale of natural gas is to an affiliate, the new regulations require the lessee to (1) pay royalties based on the gross proceeds received in the first arm’s-length sale by the lessee’s affiliate or, (2) at the option of the lessee, pay royalties based on an index pricing methodology. For arm’s length sales, the lessee must value unprocessed gas based on its gross proceeds and may not use the index pricing method.

The optional index pricing method for non-arm’s length sales looks to where a lessee’s gas could physically flow. If the gas stream could flow to several index pricing points, the index price method requires the lessee to use “the highest reported monthly bidweek price for the index pricing points to which your gas could be transported for the production month, whether or not there are constraints for that production month.” 30 C.F.R. 1206.41(c)(1)(ii). If a lessee can only transport gas to one index pricing point published in an ONRR-approved publication, value is to be determined by the highest reported monthly bidweek price for that index. 30 C.F.R. 1206.14(cc)(1)(i). For onshore production, the index price value is reduced by 10 percent (but not less than 10 cents per MMBtu or more than 30 cents per MMBtu), to account for transportation and no separate transportation allowance is allowed. Once a lessee selects an ONRR approved publication the lessee may not select a different publication more often than once every two years.

Valuation of Processed Gas

Under the new regulations, where a lessee sells gas under an arm’s length “keepwhole” or “percentage of proceeds” contract, the lessee must calculate royalties for the gas as “processed gas.” 30 C.F.R. 1206.142(a). For example, where a lessee enters into an arm’s length sales contract for the sale of gas prior to processing, but the contract provides for payment to be determined on the basis of the value of any products resulting from processing, including residue gas or natural gas liquids, the gas must be valued as processed gas – namely, based on 100% of the value of residue gas, 100% of the value of gas plant products, plus the value of any condensate recovered downstream of the point of royalty settlement prior to processing, less applicable transportation and processing allowances. The lessee may not deduct, directly or indirectly, costs for boosting residue gas at a processing plant or for fuel associated therewith. The new regulations place increased burdens on lessees who sell gas in an arm’s length contract under a keepwhole or percentage of proceeds agreement to “unbundle” costs and value natural gas liquids and residue gas recovered from processing in order to properly calculate federal royalties.

For non-arm’s length sales of processed gas, the regulations also eliminated the “benchmarks” and require the lessee to value residue gas and gas plant products by using the gross proceeds received under the first arm’s-length sales price or an optional index price method. Again, the index method for processed gas is only available where the lessee did not sell production under an arm’s length contract. The optional Index price methodology includes approved index pricing for natural gas liquids (NGLs) with a stated deduction from the index pricing points to account for processing costs (based on a minimum rather than average processing rate as determined by the ONRR) and a reduction for transportation and fractionation (T&F), also at a stated amount. No separate transportation or processing allowance may be claimed if this option is used.

Firm Cap on Transportation and Processing Allowances and Elimination of Transportation Factors

The new regulations make the 50% value cap on transportation and the 66 and 2/3rd value cap on processing allowances firm. The ONRR no longer has the discretion to permit larger allowances for extraordinary circumstances. ONRR has also eliminated transportation factors (netting of transportation costs as part of sale’s price) and now requires transportation factors to be stated in an equivalent monetary amount and claimed as a transportation allowance.

Marketable Condition

 The new regulations continue to employ the ever expanding “marketable product” rule by providing, among other things, that transportation allowances may not include costs attributable to transporting non-royalty bearing substances commingled in the wellhead gas stream, by requiring royalty to be paid on gas used as fuel, lost or unaccounted for (FL&U) (except FL&U in an arm’s length contract based on a FERC or State approved tariff), and by disallowing deductions for the costs of boosting residue gas during processing, including any fuel used for boosting. In its comments for requiring wet gas sold at the well under percentage of proceeds (POP) contracts to be valued as “processed gas,” for example, Department of Interior asserted:

[P]ast regulations did place the responsibility on lessees who sell their gas at the wellhead under POP-type contracts to place the residue gas and gas plant products into marketable condition at no cost to the Federal Government. Simply selling the gas at the wellhead does not mean the gas is in marketable condition –one must look to the requirements of the main sales pipeline. . . . “Whether gas is marketable depends on the requirements of the dominant end-user, and not those of intermediate processors.” 81 Fed. Reg. 43348 (unreported case citation omitted).

Default Provisions

The new regulations also contain “default” provisions that allow the ONRR to reject a lessee’s valuation or allowances and determine valuation and allowances by looking to other market indicia of value and allowances, and these default provisions will apply if: (1) there is no written sales contract, transportation agreement or processing agreement signed by all parties to the contract, or (2) the ONRR determines the lessee has failed to comply with applicable regulations because of, among other things, (a) misconduct by or between the contracting parties, (b) the lessee breached its duty to market the gas, (c) ONRR determines the value of gas, residue gas or gas plant product is unreasonably low (ONRR may consider a sales price unreasonably low if it is 10 percent less than the lowest reasonable measures of market price, including index prices and prices reported to ONRR for like-quality gas, residue gas or gas plant products) or (d) the lessee fails to provide adequate supporting documentation.

The new federal royalty regulations for natural gas produced from federal leases may require lessees to make significant changes in how they report and pay federal royalties, particularly where a lessee sells gas under percentage of proceeds or keepwhole sales contracts. Application of these new regulations should be carefully reviewed in light of the lessee’s sale, transportation and processing arrangements to avoid potential interest and penalties.

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Don’t Risk Litigation Over the Arbitration Clause in Your Oil and Gas Lease

The arbitration clause in an oil and gas lease is likely not the most hotly negotiated term or even one that the parties think twice about. However, recent litigation in Pennsylvania should serve as a reminder to lessors and lessees to be aware that a poorly drafted arbitration clause may lead to unwanted litigation.

Recently, the United States Supreme Court denied a petition to review Chesapeake Appalachia, LLC v. Scout Petroleum, LLC, 809 F.3d 746 (3d. Cir. 2016) cert. denied (Oct. 3, 2016), a case addressing whether an arbitration clause used in numerous oil and gas leases covering lands in the Marcellus Shale region of Pennsylvania permitted class arbitration and whether the issue of class arbitrability is one for the courts or for the arbitrators to decide. The leases contained identical gas royalty clauses (except for some differing royalty percentages). The clauses provided that Chesapeake shall pay the lessor-royalty owners a certain percentage of the proceeds Chesapeake received from the sale of gas less four specific charges: transportation, treatment, processing and volume deduction to the point of measurement. All of the leases also included the following identical arbitration provision, which was silent as to both the availability of classwide arbitration and whether the question of classwide arbitrability should be submitted to the arbitrators or the court:

ARBITRATION. In the event of a disagreement between Lessor and Lessee concerning this Lease, performance thereunder, or damages caused by Lessee’s operations, the resolution of all such disputes shall be determined by arbitration in accordance with the rules of American Arbitration Association. All fees and costs associated with the arbitration shall be borne equally by Lessor and Lessee.

Without clear language on classwide arbitration the clause resulted in opposing interpretations. Scout sought to commence class arbitration on behalf of itself and a putative class of thousands of similarly situated lessor-landowners, claiming that Chesapeake breached the leases by deducting charges for compression, gathering, and other charges not authorized by the leases, resulting in the underpayment of royalties to itself and the other class members. Chesapeake disagreed that class arbitrability was available under the leases and initiated the litigation in the Middle District of Pennsylvania, arguing that the issue was one for the courts. The District Court agreed with Chesapeake and held that the issue of arbitrability was one for the courts, and not the arbitrators, to decide. Scout appealed the District Court decision.

On appeal, the Third Circuit reiterated that there is a presumption that courts (not arbitrators) must decide questions of arbitrability, including whether a contract contemplates class arbitrability. The court stated that the burden of overcoming the presumption that the issue of arbitrability is for judicial determination is “onerous [and] requires express contractual language unambiguously delegating the question of arbitrability to the arbitrator.” Ultimately, although the court was highly critical of Chesapeake, stating that “[a]s a sophisticated business, it could have, and, at least in retrospect, should have, drafted a clearer arbitration agreement,” it held in favor of Chesapeake that the leases “do not clearly and unmistakably assign to an arbitrator the question whether the agreement permits classwide arbitration.” Scout appealed to the United States Supreme Court, which denied the petition to hear the case.

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The Dakota Access Pipeline and What It Means

On September 9, 2016, 30 minutes after winning and stopping the Standing Rock Sioux Tribe’s (“Sioux” or “Tribe”) request to enjoin the Dakota Access Pipeline (“DAPL”), the Obama administration upended the rule of law. The Departments of Justice, Army and the Interior issued a joint statement that the U.S. Army Corps of Engineers (“Corps”) “will not authorize constructing the Dakota Access pipeline on Corps land bordering or under Lake Oahe until it can determine whether it will need to reconsider any of its pervious decisions regarding Lake Oahe site under the National Environmental Policy Act (“NEPA”) or other federal laws.” The Administration then asked the company to “voluntarily pause all construction activity within 20 miles east or west of Lake Oahe.”

The DAPL is the latest energy touchpoint. Tribes from all over the U.S. are joining the Sioux as they construct a winter encampment on the Corps-managed land. Neil Young has penned a new anthem, “Indian Givers,” arguing “There’s a battle raging on sacred land/our brothers and sisters have to take a stand.” Green Party presidential candidate Jill Stein and movie actress Shailene Woodley (“The Secret Life of the American Teenager”) have been jailed in support of this energy infrastructure protest.

The DAPL is a 4-state, 1,172 mile pipeline built to transport North Dakota Bakken oil to an Illinois refinery by Energy Transfer, a Texas company. None of the pipeline right-of-way is located on Sioux land, but is within ½ mile of the reservation boundary; over 90% of the right-of-way is on private land. Only 3% of the pipeline requires federal approval and only 1% affects federal waters of the U.S. and, thus, the jurisdiction of the Corps.

The $3.8 billion pipeline is 60% complete at a cost of $1.6 billion dollars. The Corps right-of-way at issue is under Lake Oahe, a flood control project managed by the Corps on land that once was part of the Sioux reservation.

The DAPL needed a number of Clean Water Act (“CWA”) permits from the Corps. On July 25, 2016, the Corps issued its Final Environmental Assessment for 200 crossings (37 miles) of jurisdictional water of the U.S. under Nationwide Permit #12 (“NWP 12”). The CWA NWP 12 authorizes pipeline construction where the construction will affect no more than a half-acre of regulated waters at any single crossing. In addition, the Corps had to analyze several Rivers and Harbors Act of 1899 (33 U.S.C. § 408) section 408 permits including the one at issue to cross a federal flood control project, Lake Oahe.

Any “federal action” under NEPA and “federal undertaking” under the National Historic Preservation Act (“NHPA”), like the CWA permits here, triggers compliance with the procedural requirements of NEPA and NHPA. NHPA § 106, among other things, requires federal agencies to “consult” with Native Americans on impacts of “undertakings” to historical and cultural resources. The consultation is required whether or not the action is on reservation land – an historic or spiritual connection to the land suffices. Compliance is the act of consultation; consensus or approval by the Tribe is not required. The Corps approach is to consider each separate pipeline crossing as a single “undertaking” for NHPA purposes, but does not treat the entire pipeline as one undertaking. Therefore, each separate crossing has a narrow geographic focus (“area of potential effect”) for NHPA consultation.

In the Tribe’s injunction request to the D.C. District Court, the Sioux argued that the Corps did not adequately consult and that construction of the pipeline in this area threatens graves and sacred sites. The court in an exhaustive analysis of the Corps consultation action found that “this is not a case about empty gestures . . . the Corps and the Tribe engaged in meaningful exchanges that in some cases resulted in concrete changes to the pipeline’s route.”

For the Sioux, the inadequacy of the consultation was its crossing-by-crossing focus. The Tribe argued that consultation should focus on the entire length of the pipeline. Because the Corps refused this focus for the consultation, the Tribe would not formally consult. The Advisory Council on Historic Preservation, a federally chartered entity with a NHPA-directed role to play in consultations, became involved and disputed the Corps’ assertion that the entire pipeline was not subject to the Corps’ jurisdiction.

The current status of the DAPL is that the several emergency injunctions of construction for portions of the pipeline on either side of Lake Oahe have been lifted. The company continues its pipeline construction on fee land despite the Administration’s renewed request that they voluntarily stand down. The D.C. District Court is poised to consider the case on the merits, while the D.C. Circuit prepares to consider the appeal of the D.C. District Court’s September denial of the injunction. Meanwhile, the Administration has begun a nationwide consultation process with Native Americans to improve the NHPA consultation process. The Corps has told the court that it will make a decision on the Section 408 permit for the Lake Oahe crossing in “weeks not months,” but cautions that its decision could require additional process. This could include supplemental NEPA, an environmental impact statement (“EIS”) or additional NHPA consultation. It is anticipated that such action will occur after the first Tuesday in November.

But this case is bigger than the DAPL. It represents the latest stage in the 350.org “Keep It in the Ground” movement to stop not only oil and gas development but the necessary infrastructure to transport it to market. Over the last few years, oil and natural gas pipelines have faced environmental and climate change opposition across the U.S. In October, climate activists targeted 5 cross-border pipelines transporting Canadian oil sands petroleum to U.S. markets by shutting down valves. The “Keep It in the Ground” movement is an effort with serious safety and economic implications for the oil and gas industry.

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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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