WSMT is a proven leader in legal matters related to domestic and international oil and gas development. We assist our clients with all aspects of oil and gas development, including exploration permitting, lease acquisition, assistance with operational issues, representation before regulatory commissions and local governments, and plugging and aband...onment issues. We have a strong reputation for quality, expert representation before the Colorado and Wyoming Oil and Gas Conservation Commissions. WSMT attorneys also represent multinational corporations and help to evaluate international exploration and production opportunities. More

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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590 Hits

“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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1065 Hits

REVISED BLM WASTE PREVENTION/METHANE REGULATIONS FINALIZED

Effective November 27, 2018, the revised Bureau of Land Management (BLM) regulations pertaining to waste prevention will take effect. 83 Fed. Reg. 49,184 (Sept. 28, 2018). This final rulemaking eliminates several of the more onerous burdens imposed by the regulations adopted at the end of the previous Administration. 82 Fed. Reg. 83,008 (Nov. 18, 2016) (the “2016 Rule”). The 2016 Rule (sometimes called the methane rule) was officially effective as of January 17, 2017, although many of its provisions called for delayed implementation. The 2016 Rule has been the subject of conflicting rulings from the federal courts in the District of Wyoming (now in the Tenth Circuit Court of Appeals) and the Northern District of California (and briefly in the Ninth Circuit Court of Appeals). Although the adoption of the new final rule would appear to moot that litigation, the States of California and New Mexico, followed by Sierra Club and a number of other non-governmental organizations, filed new lawsuits challenging the 2018 final rule in the U.S. District Court for the Northern District of California. State of California, et al. v. Zinke, et al., Case No. 4:18-cv-05712-YGR (filed Sept. 18, 2018); Sierra Club, et al. v. Zinke, et al., Case No. 4:18-cv-05984-SBA (filed Sept. 28, 2018). Western Energy Alliance and Independent Petroleum Association of America have moved to intervene in the State of California case. This post describes the terms of the 2018 rule that will take effect November 27, 2018, barring an injunction or order vacating the 2018 rule from the federal court in California.

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826 Hits

Zero Carbon Natural Gas Would Support More Fracking and More Natural Gas Power Plants

One of the arguments against fracking, and the natural gas industry in general, is that burning gas releases carbon dioxide, which contributes to global warming.i What if burning natural gas resulted in no CO2 emissions? In the next three to five years that may be true.

MIT Technology Review has identified “zero carbon natural gas” as one of ten breakthrough technologies for 2018. NET Power, LLC is currently testing the concept with a 50-megawatt demonstration power plant in LaPorte, Texas. “The plant puts the carbon dioxide released from burning natural gas under high pressure and heat, using the resulting supercritical CO2 as the ‘working fluid’ that drives a specially built turbine. Much of the carbon dioxide can be continuously recycled; the rest can be captured cheaply.”ii NET Power plans to sell or use the remaining CO2 for enhanced oil recovery and manufacturing cement and plastics. 8 Rivers Capital invented and is advancing the Allam Cycle technology behind the project.

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2599 Hits

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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1232 Hits

IBLA Upholds ONRR $3 Million+ Penalty For A Company’s Delay In Correcting Royalty Report Forms

A recent decision of the Interior Board of Land Appeals (IBLA) vividly makes the point that the Department of the Interior considers accurate royalty reporting to be equally if not more important than payment of the proper amounts. In Quinex Energy Corp., 192 IBLA 88 (2017), the operator underpaid royalties on several tribal and allotted leases covering lands on the Uintah and Ouray Indian Reservation in Utah in the amount of $120,242 because it used “erroneous gas prices.” The decision does not explain the reason for the erroneous prices but apparently the underpaid amount was promptly paid upon receipt of the Office of Natural Resources Revenue (ONRR) order to report and pay sent to Quinex. However, it took Quinex between 8 and 22 months to correct the royalty reports on the ONRR-2014 forms that it had filed relating to the royalty underpayments. The ONRR sent civil penalty notices to Quinex assessing penalties in the aggregate amount of $3,217,250 - more than 26 times the amount of the underpaid royalty! The penalty was assessed based on $25 per day for 229 reporting violations (one for each inaccurate line on the 2014 form) that continued for between 8 and 22 months.

The ONRR has statutory authority to assess civil penalties of up to $25,000 per day per violation for knowingly or willfully preparing, maintaining or submitting false, inaccurate, or misleading royalty reports. 30 U.S.C. § 1719(d). Under the Federal Civil Penalties Inflation Adjustment Act of 1990, that $25,000 statutory maximum is now $59,834 (30 C.F.R. § 1241.60(b)(2)). At the time of the events involved in the Quinex case, $25,000 was the maximum penalty, which ONRR reduced, in its discretion, based on the size of the payor (Quinex stated that it had five full-time and four part-time employees). Although there was no allegation that Quinex had behaved willfully, the IBLA stated that it did behave knowingly, because of the significant time between receipt of notice of the order to report and pay and final correction of the reports. The regulations define “knowingly or willfully” to include an act or failure to act committed with actual knowledge, deliberate ignorance, or reckless disregard of the facts surrounding the event or violation. 30 C.F.R. § 1241.3(b). No proof of specific intent to defraud is required as a condition to assessement of a civil penalty for knowing and willful violations of the regulations.

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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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1756 Hits

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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1237 Hits

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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1129 Hits

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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964 Hits

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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1555 Hits

Wyoming Supreme Court Justices Disagree: Were Tax Assessments of Minerals Constitutional?

As noted in a prior blog post, Wyoming’s Supreme Court Justices agree most of the time. In fact, in 2016 more than 95% of the Court’s orders and opinions were unanimous. This post highlights a recent disagreement between the members of the Wyoming Supreme Court in the case of Anadarko Land Corp. f/k/a Union Pacific Land Resources Corp., and Three Sisters, LLC v. Family Tree Corporation, 2017 WY 24, 389 P.3d 1218 (Wyo. 2017) concerning a 1911 tax assessment that changed--or did it--the ownership of minerals in 2017.

This case features the appeal of a district court decision upholding the validity of a 1911 Laramie County tax assessment against minerals owned by Anadarko Land Corporation’s (“Anadarko”) predecessor-in-interest1. Anadarko’s predecessor, the Union Pacific Railroad, acquired the mineral interests at issue in a Patent issued by the United States in 1901. In 1911, Laramie County assessed taxes on these unproduced minerals. Anadarko’s predecessor did not pay the assessed taxes, and Laramie County put the mineral interests up for bid at a tax sale. When no bids were made for the mineral interests, Laramie County acquired the minerals and then, by a tax deed in 1919, sold the mineral interests to Iowa Land & Livestock Company. At this point, two divergent chains of title emerged. One chain derived from Anadarko’s predecessor and the other from the Laramie County tax sale

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1172 Hits

Colorado Legislature Considers Limitations On “Force Pooling”

Rep. Mike Foote (D-Lafayette) and Rep. Dave Young (D-Greeley) introduced House Bill HB17-1336, legislation which would prevent a lessee representing less than a majority of the mineral royalty owners from obtaining a force pooling order. The authors of the legislation argue the intent of the bill is to prevent a mineral rights owner or lessee from forcing adjacent mineral interest owners to lease their minerals and to provide better information to affected parties. In addition, the legislation would provide mineral owners with additional time to decide whether to lease, participate in proposed well(s), or decide not to participate in the drilling of proposed well(s). Proponents of the legislation also argue that under current law, an oil and gas operator has too much of an advantage when it can tell an unleased mineral owner that if he or she does not sign a lease, then they will be force pooled.

The bill was introduced late in the session where rules allow expedited consideration, with the probable strategy being to prevent extended deliberation. The bill appears to conflict with Colorado property and constitutional law. Given significant departures from existing law, a longer time is necessary to fully appreciate how current law would be changed. Here are some of the problems:

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1210 Hits

COGCC: A Balancing Act or “Subject To” Protection of Health, Safety, and Environment – A Surprising Decision from the Colorado Court of Appeals

A recent decision from the Colorado Court of Appeals (“Court”) could mean a new focus for the Colorado Oil and Gas Conservation Commission (COGCC). On March 23, a three-judge panel issued a split decision in Martinez v. Colo. Oil & Gas Conservation Comm'n, 2017 COA 37, with two of the three Judges rejecting the COGCC’s assertion that its role under the Oil and Gas Conservation Act (Colo. Rev. Stat. §§ 34-60-101 to -130) (the “Act”), is to balance oil and gas development with other public interests such as public health, safety, and welfare.

At issue was a petition for rulemaking filed with the COGCC in 2013 by members of the Boulder-based Earth Guardians asking that the COGCC “not issue any permits for the drilling of a well for oil and gas 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.” The COGCC solicited and reviewed a substantial amount of public input on the matter, and later denied the petition, finding, inter alia, that the proposed rule would require it to “readjust the balance crafted by the General Assembly under the Act,” thus making the proposed rule “beyond the Commission’s limited grant of statutory authority.” The petitioners appealed that decision to the Denver District Court, which affirmed the COGCC’s denial of the petition.

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1547 Hits

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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1541 Hits

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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