More Local Government Control Over Oil and Gas Operations? Colorado House Says No.

Over the past several years there has been an ongoing debate on whether local governments have the authority to limit or even ban oil and gas operations. In 2012, residents of the City of Longmont voted to approve a ban on hydraulic fracturing within city limits. Similarly, in 2013, Fort Collins voters approved a five year moratorium on fracking within city limits. The Colorado Oil and Gas Association challenged both bans, and the cases reached the Colorado Supreme Court. A recap on the case history and oral arguments can be found in a prior blog, “State or Local for Colorado?” A decision is expected from Colorado’s high court in 2016.

The most recent battle between state and local control of oil and gas operations was fought in the Legislative branch. On March 11, 2016, Representatives Mike Foote, Su Ryden, Jessie Ulibarri and Matt Jones of the Colorado House of Representatives (“House”) introduced House Bill 16-1355 (“HB 1355”) in an attempt to provide local governments with control over the location of oil and gas facilities. HB 1355 declares that “governing bodies of local governments are in the best position to determine the appropriate locations for oil and gas facilities and will properly balance . . . the effects on public health, wildlife, and the environment.” The Colorado Oil and Gas Conservation Commission (“COGCC”) currently has authority over the siting of oil and gas facilities in all jurisdictions in Colorado. HB 1355 states that “statewide siting rules provide an ineffective protection for the public . . . [and] local governments are in the best position to determine the appropriate locations for oil and gas facilities.” Although the bill recognized the existing authority of the COGCC, it emphasized that “the oil and gas industry is not exempt from local governments’ authority to control the siting of oil and gas facilities through existing zoning and land use authority just as they do for every other industry.”

In an attempt to gain more supporters of HB 1355, several last minute amendments were made to the original bill. The original bill proposed an addition to Colorado statutes that would require an operator to “ensure that the location of oil and gas facilities complies with city, town, county, or city and regulations.” The proposed addition to the statute authoritatively stated that “nothing in this section impairs or negates the authority of local governments to regulate the location of oil and gas facilities.”

It became clear that the House would not pass a bill providing local governments with such overarching authority to regulate the location of oil and gas facilities, especially with the Longmont and Fort Collins cases pending before the Supreme Court. Accordingly, the morning of the vote, HB 1355 was amended to remove the language giving local governments broad authority to regulate the location of oil and gas facilities. Consequently, the amended HB 1355 merely restated the current law that oil and gas facilities may be regulated by local governments under current zoning regulations.

Colorado Governor John Hickenlooper urged the House not to pass HB 1355, stating his preference that the Legislature wait until the Colorado Supreme Court issues decisions on the pending cases. Ultimately, on April 4, 2016, the watered down version of HB 1355 failed to make it out of the Democratic-controlled House.

Even though HB 1355 was a failed attempt by the Colorado Legislature to provide local governments with the power to regulate oil and gas operations, its introduction is yet another example of the sentiment of many Coloradans that local municipalities should be able to limit or restrict oil and gas operations.
A copy of HB 1355 can be found here.

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Tenth Circuit Grants Remittitur, Dramatically Reducing Large Wyoming Punitive Damages Award in Carbon Monoxide Poisoning Case

On April 1, 2016 the United States Court of Appeals for the Tenth Circuit issued a significant opinion in the personal injury case Amber Nicole Lompe, Plaintiff-Appellee, v. Sunridge Partners, LLC and Apartment Management Consultants, LLC, Defendants-Appellants, 10th Cir. No. 14-8082, vacating and reducing significant punitive damages awards against the owner and property manager, respectively, of a Casper, Wyoming apartment complex. In doing so, the Court further spelled out the legal “guideposts” that govern punitive damages awards, and brought more clarity to this controversial topic.

In February 2011, Ms. Lompe, a tenant in the Sunridge Apartments, suffered carbon monoxide poisoning from malfunctioning furnaces in her apartment building. She brought suit against Sunridge Partners, LLC (“Sunridge”), as the building owner and Apartment Management Consultants, LLC (“AMC”), as the property manager. At trial in Wyoming’s United States District Court, a jury found both defendants negligent and awarded Ms. Lompe compensatory damages totaling $3,000,000, and punitive damages totaling $25,500,000, of which $3,000,000 was apportioned against Sunridge and $22,500,000 against AMC. On appeal, defendants argued that the district court erred by failing to grant their motion for judgment as a matter of law (JMOL) as to punitive damages, and in the alternative, they contended that the district court’s jury instructions on punitive damages were incorrect and the amount of punitive damages awarded against each defendant was excessive under common law and constitutional standards.

The Tenth Circuit held the evidence at trial was insufficient even to present the issue of punitive damages to the jury as to Sunridge (as Sunridge’s conduct did not rise to the threshold level of “willful and wanton misconduct,” as required by Wyoming law), and accordingly vacated entirely the $3,000,000 award of punitive damages against Sunridge. The Court also held that, while Ms. Lompe presented sufficient evidence of AMC’s misconduct to send the question of punitive damages to the jury, the $22,500,000 punitive damages jury award against AMC was “grossly excessive and arbitrary in violation of the Due Process Clause of the Fourteenth Amendment,” and reduced that award to $1,950,000.

In reaching its decision, the Tenth Circuit provided a thorough and detailed discussion of Wyoming’s substantive law on punitive damages (e.g., what conduct amounts to “willful and wanton misconduct,” and what does not), along with a very thorough review and discussion of Tenth Circuit and United States Supreme Court precedent on punitive damages. In particular, the Court focused on “the ‘exacting de novo’ review the Supreme Court has mandated in reviewing constitutional challenges to punitive damages awards,” and then applied the Supreme Court’s “guidepost analysis” found in BMW of North America v. Gore, 517 U.S. 559 (1996). See also, State Farm Mut. Auto Ins. Co. v. Campbell, 538 U.S. 408 (2003) and Jones v. United Parcel Serv., 674 F.3d 1187, 1208 (10th Cir. 2012). The Court stated:

“Consequently, ‘the Due Process Clause of the Fourteenth Amendment prohibits the imposition of grossly excessive or arbitrary punishments on a tortfeasor.’ In reviewing a constitutional challenge to an award of punitive damages under the Due Process Clause of the Fourteenth Amendment, a federal court must ‘consider three guideposts: (1) the degree of reprehensibility of the defendant’s misconduct; (2) the disparity between the actual or potential harm suffered by the plaintiff and the punitive damages award [at times referred to as “the ratio” between the compensatory damages award and the punitive damages award]; and (3) the difference between the punitive damages awarded by the jury and the civil penalties authorized or imposed in comparable cases.’”

Applying this “guidepost analysis,” the Court determined that the $22,500,000 punitive damages award against AMC was excessive, as it was 11.5 times AMC’s share of the $3,000,000 compensatory damages award, which was $1,950,000 [the jury had assigned AMC 65% of the total fault, so 65% of $3,000,000 = $1,950,000], and that, under the facts of this case, a 1:1 ratio of punitive damages to compensatory damages was appropriate “[to] satis[fy] ‘the State’s legitimate objectives’ of punishing and deterring future misconduct”.

In sum, in the Lompe decision, it is encouraging that the Tenth Circuit has taken such a principled and disciplined approach to the review of punitive damages awards. The complete text of the Lompe opinion is available here. If you have questions about a specific legal matter that involves a possible punitive damages issue or claim, please contact Hampton O’Neill or any other WSMT attorney.

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Department of Transportation Proposes Rules Expanding Safety Regulations for Gas Gathering and Transmission Lines

The recent shale boom has greatly increased the amount of natural gas produced and transported across the country’s network of pipelines in recent years. Unfortunately, the increase in production has resulted in several significant environmental and safety incidents, including a widely reported 2010 gas pipeline explosion in San Bruno, California, that killed 8 people and destroyed more than 100 homes. As a result, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency of the Department of Transportation (“DOT”) established in 2004 tasked with regulating gas gathering and transmission lines, issued a major and controversial Notice of Proposed Rulemaking (hereinafter, the “Proposal”) on March 17, 2016, which would revise the safety and monitoring standards pertaining to the regulation of onshore natural gas pipelines.

The stated intent of the Proposal is to clarify and broaden the scope of safety regulations, including the implementation of a standardized Integrity Management (“IM”) regulatory structure that governs risk-based integrity assessment, repair, testing, and validation of gas gathering and transmission lines. The 549-page Proposal addresses congressional mandates set forth in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and six National Transportation Safety Board recommendations, and contains major and minor changes that are intended to assert the PHMSA’s control over the design, implementation, operation, maintenance, and repair of the pipelines. The PHMSA believes that, in addition to improved public safety, the Proposal will significantly reduce methane and carbon dioxide gas emissions by lowering the number of environmental incidents that have occurred with the increases in production.

However, these benefits will come at a high cost to the industry. Experts expect compliance with these changes to cost the industry more than $40 million dollars a year due to high costs stemming from the age and lack of existing information on many miles of pipelines constructed prior to 1970 and the increased regulation of previously exempt pipelines, additional natural gas gathering pipelines, and pipelines located in moderately populated areas. Further, the Proposal expands the PHMSA definition of a “gathering line”, which will subject many previously unregulated lines to increased testing and monitoring. Industry analysts are also concerned with potential service disruptions related to the implementation of these new regulations.

Comments may be submitted within 60 days after the Proposal is published in the Federal Register as a Notice of Proposed Rulemaking. Due to the number of extensive changes to the current regulatory structure, the Proposal is likely to generate many comments from the industry, environmental interest groups, state regulatory authorities, and safety advocates. As a result, the Proposal could change greatly before it is finalized.

Some of the key components of the Proposal are:

• Increased IM requirements will be required for more categories of pipelines, including many that were previously exempt

• Additional reporting of incidents and unsafe conditions, pressure testing, and new design requirements for previously exempt facilities, including those built prior to 1970

• Removal of reporting exemptions for gas gathering lines

• Increased IM testing, inspection, monitoring and repair criteria for pipelines in densely-populated areas, defined as High Consequence Areas (“HCA”)

• Creation of Moderate Consequence Areas (“MCA”), which will be subsets of non-HCA pipeline locations, defined as an area containing five or more buildings “intended for human occupancy” and certain highway and street rights-of-way, and the required assessment, periodic assessment, and remediation of discovered defects of the same (Note that MCAs will be less heavily regulated than HCAs)

• Increased requirements for collecting, validating, and integrating pipeline data, including the monitoring and recording of the physical and operational characteristics of pipelines where records are currently not available

• Disaster inspections that will require the operator to inspect all pipelines that may have been adversely affected to detect any damages in the event of a natural disaster, such as a hurricane, flood, earthquake, landslide, or other adverse natural occurrence

The Proposal is available as written on the PMHSA website here, and has been provided to the Federal Register for publication. Please contact any of our attorneys at Welborn Sullivan Meck and Tooley, P.C. if you have questions or if you need assistance filing a comment on the Proposal upon its publication in the Federal Register.

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2016 Wyoming Energy Plan – Doubling Down on Coal

In the face of a radically altered economic and energy picture for Wyoming, Governor Matt Mead released an updated energy strategy for the State on March 14, 2016. Titled “Leading the Charge: Wyoming’s Action Plan for Energy, Environment, and Economy,” the plan is an update of a similar report issued by the State in 2013, the first of its kind in the nation. The State is facing significant budget challenges from the loss of royalty income, severance taxes, and jobs from low oil and gas prices and the even more dramatic decline of coal mine revenue as key coal mining companies in the State seek bankruptcy protection. Approximately 60% of State government revenues come from mineral development.

Gov. Mead proposes to meet the budget challenges by addressing the backbone of the State’s economy – energy development. The 2013 report set forth 45 initiatives, 28 of which have been completed, and the 2016 strategy adds several new priorities. Emphasizing his commitment to the coal industry, the Governor summed up his approach as “a doubling down on coal and a very good start on renewables.” Specifically, the energy plan includes:

• A “carbon innovation” effort for the development of “clean coal” technologies by building on the success of the Integrated Test Center, a public-private partnership with the XPRIZE, to develop and test new technologies for the capture of CO2 emissions.
• Harnessing Wyoming’s Class 5-7 wind energy resources with a new Wind Energy Manufacturing Initiative, led by the Wyoming Business Council. The goal would be to attract wind turbine manufacturing to the State.
• Hosting a symposium to explore how to turn the devastation caused to Wyoming forests by the Pine Beetle on its head by integrating biomass energy into the State’s overall energy plan.
• Forming a National Environmental Policy Act Team to work with federal agencies to expedite the NEPA process to work more collaboratively with BLM in land use planning and combatting invasive species on public land.
• Identifying and working to reduce areas of duplication in State and Federal regulations.
• In light of coal company bankruptcies and self-bonding the State had permitted earlier, Wyoming must urgently address coal mine reclamation liabilities. The energy strategy accordingly calls for an examination of the adequacy of reclamation formulas, reviewing reclamation goals and definitions, and analyzing the self-bonding program.
• Diversifying the State’s economy by increasing the emphasis on international exports including coal, oil and gas (LNG), uranium and other resources.
• The strategy also addresses rulemaking proposals, including baseline groundwater testing before oil and gas drilling, setback requirements, a review of flaring rules, and mitigation banking and additional efforts for the protection of Greater sage-grouse.

Gov. Mead hopes that this year’s plan will continue to allow the State to be proactive in planning its future energy development, which will in turn create additional economic and business opportunities for both new and existing industries. The Governor asked for $500,000 to implement the energy strategy in the 2017-2018 budget, which was rejected by the Legislature, so it remains to be seen how much of the plan he will be able to implement.

The full text of Wyoming’s Action Plan can be found here: http://governor.wyo.gov/media/news-releases/2016-news-releases/governormeadannouncesupdatedenergystrategy.

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Who Determines What Constitutes a “Reasonable Offer to Lease” When it Comes to Involuntary Pooling? Another Example of Local Governments Attempting to Assert Control

One of the more loosely used terms from Colorado’s Conservation Act and Colorado Oil and Gas Conservation Commission (“COGCC”) Rules, and one of many lawyers’ favorite words to analyze, is the term “reasonable.” When filing for an involuntary pooling application in front before the COGCC, an applicant must comply with COGCC Rule 530, which requires the applicant to, among other things, provide an unleased owner with a “reasonable offer to lease.” In determining whether a lease offer is reasonable, the COGCC shall consider the: (1) date of the lease and primary term or offer with acreage in the lease, (2) annual rental per acre, (3) bonus payment or evidence of its non-availability, (4) mineral interest royalty, and (5) such other lease terms as may be relevant.

Despite the COGCC having been expressly tasked with determining what constitutes a reasonable offer to lease, protesting parties often try to assert themselves as the decider of what is reasonable. This issue recently came to a head. Weld County, as an unleased mineral owner, argued it was the ultimate decision-maker of what is “reasonable” when it comes to a lease offer subject to COGCC Rule 530. Section 30-11-303(1), C.R.S., grants the County the power to lease its oil and gas interests on terms as the County deems to be in its best interest. Accordingly, the County enacted Section 2-2-70, W.C.C., which established the minimum lease terms for tracts of County minerals larger than 40 acres, which are a 3-year primary term, $600 per-acre bonus, and a royalty of not less than 25%. The County therefore argued that any lease terms offered by an operator that are less than those provided in Section 2-2-70, W.C.C., are per se unreasonable because such terms would be contrary to the County’s determination of what is in its best interest. The County went so far as to argue that COGCC should defer to the terms and conditions of Section 2-2-70, W.C.C., as being dispositive as to the issue of whether or not a reasonable offer was made because the terms and conditions were "legislatively determined to be in the best interests of the citizens of Weld County".

In a prehearing order, the COGCC rejected Weld County’s claim that it could determine whether there was a reasonable offer to lease. In denying the protest, the COGCC reasoned that

Weld County cites no legal authority for the proposition that it, and not the Commission, is the appropriate political subdivision of the State of Colorado to determine what terms are just and reasonable in the context of the issuance of an involuntary pooling order. Weld County's position contradicts the plain language of §34-60-116(6), C.R.S., which authorizes the Commission to determine what terms and conditions are "just and reasonable," and §34-60-105(1), C.R.S., which rescinds county authority over all oil and gas conservation and unqualifiedly confers this authority on the Commission. To conclude otherwise would leave to Colorado counties the task of determining reasonableness of terms and conditions of pooling orders. This the legislature did not intend to do, as explained in the discussion in the preceding part of this order, and therefore, Weld County's legal argument is rejected.

Weld County’s protest and assertion that it, not the COGCC, should determine what constitutes a reasonable offer to lease under COGCC Rule 530 and the involuntary pooling statute, Section 34-60-116, C.R.S., are symptomatic of Colorado counties and municipalities desiring to assert more local control over oil and gas operations. As demonstrated by the COGCC’s recent rule making initiated by the Governor’s Oil and Gas Task Force, the counties and municipalities appear to be gaining an additional foothold on oil and gas regulation, which has been and should remain the exclusive jurisdiction of the COGCC. Indeed, allowing each county greater independent authority in regulating oil and gas development would lead to even greater unpredictability for operators, which is detrimental to efficient and economic development of the state’s oil and gas resources.

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Energy Sector Layoffs-Considerations for Employers

Downsizing and employee layoffs are the harsh reality of the plunging oil prices, as reflected by the announcements of many oil and gas companies in recent weeks. When a reduction in force becomes unavoidable, employers with Colorado operations should take steps to ensure compliance with Colorado and Federal laws, as well as contract obligations. Highlighted below are a few of the legal issues that such employers will face in a layoff.

 Managing Risk

To avoid a wrongful termination claim or lawsuit, employers should use objective criteria in selecting employees for job separation that is well documented. Once an initial group is selected, the group should be viewed as a whole to determine whether a disproportionate percentage falls within a protected employee category, such as age, disability and race. Employers should also assess risk on an individual basis, with consideration of any recent protected activity by the employee or military status.

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University of Wyoming Enhanced Oil Recovery Institute Launches New Interactive Data Platform

The University of Wyoming’s Enhanced Oil Recovery Institute (“EORI”) recently made available to the public a new Interactive Data Platform (“IDP”). The IDP allows users to display and identify oil and gas information from the Wyoming Oil and Gas Conservation Commission, the Wyoming State Geological Survey, the Wyoming Geological Association, and the Wyoming Pipeline Authority, using an interactive map. Additionally, the IDP allows users to search by location, field name and/or geological formation. The IDP is just the latest resource from the EORI.

The EORI was created by the Wyoming State Legislature to work with the State of Wyoming and Wyoming energy producers to recover stranded oil in depleted oil reservoirs as rapidly, responsibly and economically as possible. The EORI estimates that additional recovery of oil from Wyoming’s depleted oil fields using advanced enhanced oil recovery technology could total more than 1 billion barrels of additional production over the next 20 years. The EORI is primarily focused on the application of new technology through field demonstrations, and supports additional development work to support commercial-scale implementation. The EORI also frequently collaborates with the University of Wyoming’s Carbon Management Institute and the Center for Fundamentals of Subsurface Flow.

The IDP is an outgrowth of the work being done by the EORI. As a web based application, the IDP includes real-time, updated data, which will allow the application to improve and grow over time. Where possible the IDP directs users to the original sources of the information contained in the online application. If you are interested in learning more about the EORI, or about the other projects the EORI is currently focused on, it can be found online at http://www.uwyo.edu/eori/. The IDP can be accessed at http://eori.wygisc.org/

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Proposed Colorado Legislation Would Modify the Reasonable Accommodation Doctrine

Colorado House Bill 16-1310 was introduced on March 2, 2016, by State Senator Morgan Carroll (D) and State Representative Joseph Anthony Salazar (D). Under current Colorado law, to prevail on a claim against an oil and gas operator, the surface owner must present evidence that the operator's use of the surface “materially interfered” with the surface owner's use of the surface. Colo. Rev. Stat. § 34-60-127(3)(a). The proposed legislation, however, provides that an operator is strictly liable (i.e. liable without proving fault) if the operator’s oil and gas operations (including a hydraulic fracturing treatment or reinjection operation) cause an earthquake that damages real or personal property or injures an individual. Under the bill, the plaintiff establishes a prima facie case of causation if the plaintiff shows that (1) an earthquake has occurred; (2) the earthquake damaged the plaintiff’s property or injured the plaintiff; and (3) the oil and gas operations occurred within an area that has been determined to have experienced induced seismicity by a study of induced seismicity that was independently peer-reviewed.

The proposed legislation also expands the pool of potential claimants. The current law provides a cause of action to the surface owner, while the proposed bill provides that if the liability arises from an earthquake as described above, then the owner of the property or the injured person would have a cause of action.

Currently, an action under the statute must be commenced within one year of the date of the alleged violation. Colo. Rev. Stat. § 34-60-115. The bill provides that a plaintiff would have five years after discovery of the damages or injury to file an action pursuant to this statute.

The introduction of strict liability is a substantial change to the reasonable accommodation doctrine in Colorado. The full text and status of House Bill 16-1310 may be found at: https://www.billtrack50.com/BillDetail/723088

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Upon the Death of Justice Scalia, the Clean Power Plan Gains New Life

The Obama Administration, through the Environmental Protection Agency (“EPA”), announced the implementation of the Clean Power Plan (“CPP”) in August of 2015. The CPP has the stated purpose of “establishing guidelines for states to follow in developing plans to reduce greenhouse gas emissions from fossil fuel-fired electric generating units,” or, in layman’s terms, to cut carbon emissions from power plants. At that time, fifteen coal-reliant states filed for an emergency stay of the CPP with the U.S. Court of Appeals for the District of Columbia Circuit. The court dismissed the petition on September 9, 2015, stating that it was untimely because the final regulation had not yet been properly published. On January 21, 2016, the D. C. Circuit Court denied the requested stay on its merits. On January 26, 2016, officials of twenty-nine states appealed to the U.S. Supreme Court, requesting a stay pending the resolution of litigation regarding the regulation. The appellants argued that the CPP provided the EPA with too much power, which would result in the EPA pushing for the use of wind and solar at the expense of older energy-generating plants that burn coal or oil.

In a 5-4 ruling on February 9, 2016, the Supreme Court ordered the Obama Administration to stay any efforts to implement the CPP until the completion of all legal challenges to the same. This stay will remain in place while courts consider more than 30 lawsuits pertinent to the CPP. While the Supreme Court stay of the CPP is not final, it placed the Obama administration’s environmental agenda in peril. Following the ruling, the White House expressed its disappointment as follows:

We disagree with the Supreme Court's decision to stay the Clean Power Plan while litigation proceeds. The Clean Power Plan is based on a strong legal and technical foundation, gives states the time and flexibility they need to develop tailored, cost-effective plans to reduce their emissions, and will deliver better air quality, improved public health, clean energy investment and jobs across the country, and major progress in our efforts to confront the risks posed by climate change.

Even if the rule is eventually upheld, the stay will adversely affect compliance timelines set forth for states and utilities. The CPP requires states to submit implementation plans as early as this year (with possible extensions to 2018) in order to reduce greenhouse gas emissions from existing power plants by 2022. This would result in carbon emissions reductions of 32 percent from 2005 levels by 2030.

The EPA enacted the CPP under a section of the Clean Air Act that has been rarely used since it was passed in 1970. Justice Antonin Scalia, writing for the majority, noted that “[w]hen an agency claims to discover in a long-extant statute an unheralded power to regulate a significant portion of the American economy, we typically greet its announcement with a measure of skepticism.” The stay indicated that the conservative majority of the Court foresaw a reasonably high likelihood that the challengers to the CPP would probably win their case, and that the denial of the stay would result in irreparable voluntarily harm.

However, the recent death of Justice Scalia puts the CPP in a much more stable position than it would have been otherwise. The sitting panel of the D.C. District Court, which will decide the challenge, is composed of a majority of judges appointed by Democratic Presidents that would likely uphold the regulations. A majority of the Supreme Court would then be needed to overturn the D.C. Circuit Court’s decision. This seems unlikely, as the Court as it stands now is deadlocked at 4-4. If the Obama Administration is able to fill the vacancy on the Court or if a Democratic successor to President Obama is elected, the Court would likely uphold the CPP by a 5-4 vote. On March 3, 2016, Chief Justice John Roberts refused a similar request by 20 states to stay an EPA regulation limiting mercury and other toxins from power plants as it undergoes a lower court challenge, a move that some pundits claim evidences a shift of power on the Court.

In any regard, the EPA plans on pushing forward with the implementation of the CPP. At a recent conference in Houston, EPA Administrator Gina McCarthy expressed confidence that the CPP would survive these on-going legal challenges, and she pledged that the EPA would, in the meantime, continue to help states that wanted to continue to implement the CPP by choice. In her words, “[t]he stay doesn’t preclude the EPA from continuing to make progress on climate change. Are we going to respect the decision of the Supreme Court? You bet we are. But that doesn’t mean we won’t continue to support any state that voluntarily wants to move forward.”

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Electronic Communication in Modern Litigation

It goes without saying that use of electronically stored information constitutes a fundamental component of any modern, successful company, but state and federal courts have only recently adjusted their rules of discovery to reflect that. For example, the federal courts recently revised their Rule 37, which concerns sanctions for failing to preserve or produce documents relevant to a claim or defense. Previously, Federal Rule 37(e) permitted sanctions for a party’s failure to preserve electronic information only in “exceptional circumstances.” Now, Rule 37(e) places an affirmative duty on parties to take “reasonable steps to preserve” electronic information, and that duty begins the moment litigation is anticipated, not merely commenced. State courts often follow the federal judiciary’s example—whether by expressly revising their rules in accordance or simply as an example to guide decisions when their rules are silent on an issue (as Colorado’s rule is)—so these changes are significant regardless of forum.

For businesses and individuals, the added focus on electronic information both increases a party’s discovery obligations but also protects against destruction of evidence, thereby ensuring that litigation proceeds fairly and reaches a just result in light of all the facts. Gone are the days where “routine” or “automatic” system maintenance could destroy large swatches of evidence adverse to a party. In practice, a party could easily defend against its opposition’s requests for electronic information by hiding behind a wall of technological jargon designed to excuse (or confuse) the issue entirely. The old rule placed the burden on the requesting party to prove “exceptional circumstances”—an almost impossible standard to meet without smoking-gun evidence, especially in light of judges’ reluctance to wade into the “new world” of technology.

The revised rule, however, essentially flips the burden to rest on the party unable to produce electronic evidence. Now, it must explain what “reasonable steps” it put in place to preserve this information from the moment litigation was anticipated. Given the amorphous meaning of “anticipated,” companies now must be very careful not only to begin preserving electronic information once a dispute is foreseen, but they must also disable automatic system maintenance and inform employees about routine procedures that could delete or affect such information. In light of these rule changes, electronic discovery now takes a much larger role in any case, but it is a role commensurate with the already widespread use of technology in the modern, successful company

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Ski Area Water Rights: Federal Water “Grab” Resolved?

The United States Forest Service (“Forest Service”) manages 193 million acres of public lands that provide 20 percent of the nation’s clean water supply worth an estimated $7.2 billion per year. Management of public lands by the Forest Service includes issuance of special use permits for 122 ski area operations in thirteen states. 116 of the ski areas are located in 10 Western states, where water is often scarce. Although the U.S. Government owns the land, the ski areas must appropriate or acquire water rights under state law for snowmaking and other uses. The special use permits do not automatically give water rights to ski area lessees.

In 2011 the Forest Service issued a directive requiring joint ownership of existing water rights by ski areas and the United States. The directive sought to address the concern that ski areas might sell their water rights for a hefty profit rather than allow future operators of the ski area to continue use of the water right after an existing operator’s lease expires. Because the lessee historically held the water rights, this directive would have resulted in either: (1) a transfer of water rights into shared ownership with the Forest Service, or (2) a complete transfer of the water rights to the Forest Service. Critics of the 2011 directive quickly claimed that the proposal amounted to a federal water grab that would complicate operations, undermine the skiing industry, and devalue ski area leases. Opponents claimed that requiring federal ownership of water rights would limit ski areas’ ability to control their assets and operations.

The National Ski Areas Association sued the Forest Service to set aside the 2011 directive, arguing that the Forest Service should have allowed for notice and comment, a process providing for public involvement in federal decision-making. Nat’l Ski Areas Ass’n v. U.S. Forest Serv., 910 F. Supp. 2d 1269 (D. Colo. 2012). The court agreed and ruled that the Forest Service violated its own procedural rules, failed to evaluate the economic impact of the proposed directive, and violated the ski areas’ rights. The court vacated the 2011 directive for these failures to comply with procedural requirements.

The 2011 directive also sparked legislative reaction. Colorado Senator Cory Gardner proposed an amendment to the budget aiming to protect the supremacy of state water law over one clause of the Forest Service directive that sought to supersede state water law. The successful amendment established a deficit-neutral reserve fund relating to “protecting communities, businesses, recreationists, farmers, ranchers, and other groups that rely on privately held water rights and permits from Federal takings.” Similarly, Representative Scott Tipton proposed a specific water rights bill to “protect private water rights from uncompensated federal takings.” Although Representative Tipton’s bill did not pass, the joint Congressional efforts reflect the concern for privately-held water rights.

On June 23, 2014, the Forest Service posted notice of a new proposed directive with amended clauses addressing special use permits and associated water rights. The new proposed directive sought to provide assurances that sufficient water rights remain with the ski area permit for snowmaking and other essential operations (even if the ski resort is sold) but without requiring ski areas to transfer water rights to the Forest Service. The proposal allowed the ski area to continue to own the water rights as a special use permit holder, with the commitment that adequate water stay dedicated to operation of the ski area.

Forest Service Chief Tom Tidwell expressed his support for the proposed new directive: “Chair lifts can be replaced and lodges can be rebuilt, but once the water necessary for ski area operations is no longer available, the public loses opportunities for winter recreation. The economic effects of the loss of water may be far reaching. This issue has implications far beyond the boundaries of ski areas.”

After an extended public comment period, the Forest Service released its Final Directive on Forest Service permits for Ski Area Water Rights on December 30, 2015. The Final Directive requires an applicant for a ski area permit to submit documentation prepared by a qualified hydrologist or licensed engineer that demonstrates there is sufficient water to operate a ski area for the entirety of the ski area permit. “Sufficient water to operate a ski area” means that the applicant has adequate rights, or access to a sufficient quantity of water, to operate the permitted facilities, and to perform the associated activities authorized under the ski area permit under an operating plan. In determining whether a ski area applicant has sufficient water, the applicant’s hydrologist/engineer will consider typical conditions, taking into account variations due to weather and climate, technology, and infrastructure improvements.

The Final Directive further provides that if there is a change in ownership at any time, and a ski area “water facility” (defined as “a ditch, pipeline, reservoir, well, tank, spring, seepage, or any other facility or feature that withdraws, stores, or distributes water”) will no longer be used primarily for operating a ski area, the authorization for the facility under the ski area permit will be terminated and the water facility must be removed from Forest Service lands. If a ski area permit is terminated or revoked, the holder must give a right of first refusal for the water rights associated with the permit to the succeeding ski area permit holder. If the water use right is jointly owned with the United States, the holder must give a right of first refusal to the government.

Water use rights are valuable business assets for ski areas and considered necessary for operation in the arid West. Both the Forest Service and the ski industry consider the Final Directive, which took effect on January 29, 2016, to be a success. Time will tell if the dispute is truly resolved. In the meantime enjoy the powder!

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1938 Hits

BLM Proposes “Planning 2.0” Rules

On February 11, 2016, the Bureau of Land Management (“BLM”) announced significant proposed amendments to its land use planning rules as a part of its Planning 2.0 initiative. The stated goals of the proposed rules are to: (1) improve the BLM’s ability to respond to social and environmental change in a timely manner; (2) provide meaningful opportunities for other Federal agencies, State and local governments, Indian tribes, and the public to be involved in the development of BLM resource management plans (“RMPs”); and (3) improve the BLM’s ability to address landscape-scale resource issues and to apply landscape-scale management approaches.

The Federal Land Policy and Management Act of 1976 (“FLPMA”) requires that BLM develop land use plans “which provide by tracts or areas for the use of the public lands.” The BLM has historically prepared RMPs on a field office basis, but FLPMA does not prohibit the preparation of RMPs on larger or smaller areas of the public lands. The proposed rule allows the BLM Director to designate the area that will be covered by an RMP; presumably, those areas will generally be larger than the boundaries of a BLM field office’s jurisdiction so as to accommodate “landscape-scale management approaches.” However, the proposed rule does not establish any standards or guidelines for how the BLM Director will designate an area to be covered by an RMP; it simply states that the Director will “determine” the planning area for the preparation of each RMP.

A new step in the planning process will be the preparation of a “planning assessment.” The planning assessment will be prepared on the planning area so presumably will not be relied upon for the Director’s determination of the planning area. As a practical matter, BLM already prepares a form of planning assessment under the existing rules as it begins the process of preparing a new RMP, but the proposed rule formalizes that information gathering process and requires public involvement.

While the preamble to the proposed rule mentions the need for a more nimble approach to planning that is responsive to a rapidly changing environment and conditions, the expanded public involvement requirements that would be imposed by the rule will make the process anything but nimble. Public involvement, “appropriate to the areas and people involved,” is required (1) in the preparation of the planning assessment (both during the data gathering phase and on the report that documents the planning assessment which is to be made available for public review); (2) in identifying planning issues (the BLM will notify the public and make available for public review the preliminary statement of purpose and need); (3) by making the preliminary alternatives to be analyzed in the environmental impact statement (“EIS”) for the RMP and the preliminary rationale for those alternatives available for public review before the draft RMP and draft EIS are released for comment; (4) by making available for public review, before release of the draft RMP/EIS, the preliminary procedures, assumptions, and indicators that will be used to estimate the effects of implementing each alternative to be analyzed in the draft; (5) at the time the draft RMP is released for public comment; and (6) after the proposed RMP is released by providing for protests of the proposed RMP.

Although the current planning process provides for comments in response to the scoping notice published at the commencement of the EIS on the plan, comments on the draft RMP, and protests, the proposed rule adds at least three more occasions for which public involvement must be solicited. Interestingly, the proposed rule does not contemplate public involvement in the determination of what area will be covered by an RMP. As discussed by Rebecca Watson in her article on Planning 2.0, State and local governments and Indian tribes may be dissatisfied with what they are likely to view as the dilution of their input into the BLM planning process if RMPs cover “landscape” size areas, rather than the area administered by the BLM field office. See, Rebecca W. Watson and Joshua B. Cannon, “Toward Planning 2.0: The New Landscape of BLM Planning,” 93 Denv. U. L. Rev. Online 49, Nov. 2015. Moreover, the Director’s role in determining the area to be covered by an RMP (with that determination requiring no public involvement) creates the risk that the planning process will become more centralized in Washington—a development with which the word “nimble” is rarely associated.

There will be a 60-day comment period on the proposed rules beginning as of the date of publication of the draft rule in the Federal Register. Publication is anticipated by the end of February 2016.

The text of the proposed revisions to BLM planning regulations is available here.

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Weed and Water - Can water be used for marijuana cultivation in Colorado?

The question has become important to marijuana growers after the Colorado Supreme Court’s decision in Coats v. Dish Network, LLC, 303 P.3d 147 (Colo. 2015), where the Court held that an activity is only “lawful” if it violates neither state nor federal law.

The issue has now arisen in the water context before Water Division 5. In Re High Valley Farms, LLC, 14CW3095. In that case, the Division Engineer has demanded that “[t]he applicant must explain how the claim for these conditional water rights [the water is to be used for an indoor marijuana grow facility] can be granted in light of the definition of beneficial use as defined in C.R.S. § 37-92-103(4). Specifically, beneficial use means ‘the use of that amount of water that is reasonable and appropriate under reasonably efficient practices to accomplish without waste the purpose for which the appropriation is lawfully made.’”

In Coats v. Dish Network, LLC, 303 P.3d 147 (Colo. 2015), the Colorado Supreme Court held that “lawful,” as used in an employment statute where it was not further defined, should be interpreted based on its ordinary meaning. Id. at 150. The “ordinary meaning of ‘lawful’ is that which is ‘permitted by law.’” Id. So, “for an activity to be ‘lawful in Colorado, it must be permitted by, and not contrary to, both state and federal law.” Id. at 151.

Like the statute in Coats, the statutes governing water rights in Colorado do not define “lawful.” Thus, Coats seemingly dictates that the ordinary meaning of “lawful,” as meaning lawful under both federal and state law, applies. That would mean that growing marijuana is not a beneficial use and therefore not an allowed use of water pursuant to Colorado water law. There are, however, at least three reasons to believe that growing marijuana can be considered a beneficial use despite the broad language in Coats: 1) there is a constitutional right to divert water that cannot be curtailed by statute, 2) the statutory definition of beneficial use does not necessarily prohibit using water for illegal purposes, and 3) policy considerations in the water context, unlike the employment context, weighs in favor of interpreting lawful to mean lawful under state law only.

First, although beneficial use is statutorily defined, the right to divert for beneficial use derives from the Colorado Constitution. Colo. Const., Art. XVI, §§ 5-6. The Colorado Supreme Court has interpreted this to mean that the legislature “cannot prohibit the appropriation or diversion of unappropriated water for useful purposes.” Fox v. Div. Engineer for Water Div. 5, 810 P.2d 644, 646 (Colo. 1991). The Colorado Constitution establishes that marijuana grow is a useful purpose. Colo. Const., Art. XVIII, § 16. It should therefore be possible to appropriate water to grow marijuana, regardless of the statutory definition of beneficial use, because the legislature cannot abrogate the constitutional right to divert water for a purpose that is protected by the constitution.

Second, it is not readily apparent that “lawfully” modifies “the purpose” in the statutory definition of “beneficial use.” Pursuant to the last-antecedent canon of construction, “lawfully” modifies “appropriation” – not “purpose.” Thus, the appropriation must be accomplished lawfully in accordance with Colorado water law, but the water does not necessarily have to be used for a lawful purpose to effect an actual appropriation. In fact, the prior appropriations doctrine arose in the west to administer water rights when miners were using water to illegally mine federal lands prior to the General Mining Act of 1872. Thus, the statutory definition of “beneficial use” does not preclude appropriation of water for an illegal purpose as long as it is diverted in accordance with the law.

Third, Coats involved employment discrimination, an area of extensive federal regulation where policy concerns weighed in favor of allowing employers to discharge employees for violations of federal law. Id. Unlike employment law, water law is uniquely controlled by state law. 43 U.S.C. § 666 (subjecting the U.S. to state law in water rights cases); See also Bureau of Reclamation, Reclamation Manual (Temporary Release): Use of Reclamation Water or Facilities for Activities Prohibited by the Controlled Substances Act of 1970, PEC TRMR-63 (May 16, 2014) (prohibiting the use of BOR water for marijuana grow facilities, while not prohibiting the use of other water passing through BOR facilities for marijuana grow facilities). Further, policy arguments favor interpreting beneficial use as encompassing marijuana grow because the objective of Colorado water law is “the optimum use of water consistent with preservation of the priority system of water rights” C.R.S. § 37-92-501(2)(e). There is no doubt that marijuana grow is optimal in the sense that it can lead to greater revenues both per acre planted and per acre-foot of water used than most other crops grown in this state. Lawful should therefore, for the purpose of water law, be interpreted to relate only to state law.

While marijuana growers in Colorado should prevail against a challenge that their use is not beneficial, the safer course of action may still be to apply for indoor irrigation, commercial, and industrial use, without specifying the type of crop to be grown. That may also allow greater flexibility for future changes in the type of crop grown.

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2314 Hits

Proposed BLM Venting and Flaring Rule

On February 8, 2016, the BLM published its long awaited proposed rule to control venting, flaring and leaks of natural gas from oil and gas operations on onshore Federal and Indian lands. 81 Fed. Reg. 6616. The primary purposes of the rule are to: (1) update regulatory requirements in light of newer technology; (2) increase royalties payable to the government and Indian Tribes by capturing more gas; and (3) address concerns about climate change by reducing the amount of methane released to the atmosphere. The rule would supersede requirements dating back to 1979 – Notice to Lessees and Operators of Onshore Federal and Indian Oil and Gas Leases (NTL-4A), 44 Fed. Reg. 76600 (Dec. 27, 1979).

BLM studied Colorado’s Air Quality Control Commission Regulations and consulted with State regulators, referring to Colorado more than 40 times in the description of the proposed rule. Because Colorado has already adopted aggressive regulations to control methane emissions, the effect of the proposed rule would not be as great in Colorado as in other states. The proposed rule would more significantly affect operators in states such as North Dakota, South Dakota and New Mexico, where over 90 percent of routine flaring of associated gas from development oil wells occurs.

Waste Minimization Plan
A novel feature of the proposed rule that would complicate the drilling of development oil wells is a waste minimization plan that operators must submit with each Application for Permit to Drill (APD). The waste minimization plan must provide a strategy explaining how the operator will capture associated gas upon the start of oil production and include the following information:

The pipeline infrastructure location and capacity in the area of the well or wells; the anticipated timing, quantity, and production decline curve of oil and gas production from the well or wells; a gas pipeline system location map showing the operator’s wells, gas pipelines, gas processing plant(s), and proposed routes for connection to the pipeline; certification that the operator has provided one or more midstream processing companies with information about the operator’s production plans, including the anticipated completion dates and gas production rates of the proposed well or wells; the volume and percentage of produced gas the operator is currently flaring or venting from wells in the same field and any wells within a 20-mile radius of that field; and an evaluation of opportunities for alternative on-site capture approaches, if pipeline transport is unavailable.

Failure to submit a complete and adequate plan would be grounds for denying the APD.

Royalties
Although the proposed rule would not itself raise royalty rates above the current maximum of 12.5 percent, it would give BLM the flexibility to ask for a higher percentage on new leases. Recent BLM data “showed that the royalty rates charged on private and State lands range from 12.5 to 25 percent, and that the average rate assessed exceeds 16.67 percent.” Royalty rates on existing BLM leases would not be affected, but BLM is clearly paving the way to increase royalty rates on certain leases in the future.

BLM would also impose royalties on more flared gas. In addition to royalties that are due on any “avoidably lost” oil or gas, operators would also owe royalties on any gas vented or flared above a certain threshold. No more than 1,800 Mcf per month per well, averaged over all of the producing wells on a lease, could be vented or flared from development oil wells. This limit would be phased in over three years, starting with 7,200 Mcf in the first year. In the second year the limit would be 3,600 Mcf and then drop to 1,800 Mcf in the third and subsequent years.

BLM estimates that engineering compliance and other costs to industry from the proposed rule would be in the range of $117 to 161 million per year. These costs would be partially offset, however, by revenue from the sale of natural gas that would otherwise have been lost. It remains to be seen how much of a disincentive the new rule will be for drilling on public lands. Will the royalties from newly captured gas be more than the revenues lost due to operators deciding to drill elsewhere because of the new rule?

Comments on the proposed rule must be received by April 8, 2016.
The text of the proposed rule may be found at: https://www.gpo.gov/fdsys/pkg/FR-2016-02-08/pdf/FR-2016-02-08.pdf

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Assuring Your Covenants “Run with the Land”

Developers and owners of real property typically enter into a variety of contracts concerning the use of real property. This is particularly true in the natural resource extraction industry. Generally, under Colorado law contractual obligations may be deemed personal covenants that bind only the parties signing the agreement, or they may be covenants that “run with the land” and bind successors-in-title. In order for a covenant to run with the land, however, two primary elements must be established: 1) the parties to the covenant intended it to run with the land, and 2) the covenant “touches and concerns” the land (i.e. it must closely relate to the land, its use, or its enjoyment). If either element is not present, the covenant will generally not bind successors-in-title.

If parties to an agreement intend to create covenants that run with the land, it is important the agreement itself contain express language to this effect, together with express language stating that the obligations under the agreement will bind and inure to the benefit of successors and assigns. It is also important that the agreement is recorded in the real property records to put future successors-in-title on record notice of the covenants. “In order for a covenant to run with the land, there must be an intent by the parties to the covenant that it do so,” Cloud v. Ass’n of Owners, Satellite Apt. Bldg., Inc., 857 P.2d 435, 440 (Colo. App. 1992), and such intent “turns on the construction of relevant documents.” Lookout Mountain Paradise Hills Homeowners’ Ass’n v. Viewpoint Assocs., 867 P.2d 70, 74 (Colo. App. 1993). Courts resolve all doubts against the restriction and in favor of free and unrestricted use of property. K9Shrink, LLC v. Ridgewood Meadows Water and Homeowners Ass’n, 278 P.3d 372, 377 (Colo. App. 2011).

Courts have refused to find a covenant runs with the land even when the covenant is included in an instrument that contains a general provision stating the instrument shall be binding upon successors and assigns. In TBI Exploration, Inc. v. Belco Energy Corp., for example, the Fifth Circuit affirmed that under Colorado law, a covenant in a Participation Agreement to drill exploratory wells was not a covenant that ran with the land even where the Participation Agreement contained general language stating the agreement shall be binding upon the parties’ “and their respective successors and assigns.” 220 F.3d 586, 2000 WL 960047, *4 (5th Cir. 2000) (not designated for publication) (applying Colorado law). The Fifth Circuit explained that the requirement that real covenants be expressed in specific and unambiguous terms carries force because “nonparties and successors-in-interest who did not participate in the negotiations to the principal agreement should be able to determine their respective rights and obligations from the face of the principal agreement.” Similarly, in Midcities Metropolitan Dist. No. 1, v. U.S. Bank Nat’l Ass’n, 2013 WL 3200088, at ** 4 and 6 (D. Colo. June 24, 2013) Judge Babcock found as a matter of law that where Deed did not expressly reference any of the covenants in its Article II as being covenants that run with the land or binding on the parties’ successors and assigns, such covenants did not run with the land despite general language stating “[t]his Deed shall be binding upon and inure to the benefit of the parties hereto and their successors and assigns.”).

It is also important to keep in mind Colorado recording statutes, including C.R.S. § 38-35-108, which provides:

When a deed or any other instrument in writing affecting title to real property has been recorded and such deed or other instrument contains a recitation of or reference to some other instrument purporting to affect title to said real property, such recitation or reference shall bind only the parties to the instrument and shall not be notice to any other person whatsoever unless the instrument mentioned or referred to in the recital is of record in the county where the real property is located. Unless the same is so recorded, no person other than the parties to the instrument shall be required to make any inquiry or investigation concerning such recitation or reference.

Because parties are presumed to contract with knowledge of applicable law, the failure to record a contract or instrument in the real property records to put successors-in-title on record notice thereof is evidence that the parties to the agreement did not intend for contractual covenants to bind successors-in-title at the time it was entered. This holds true even if a later successor-in-title had actual knowledge of the covenant when it acquired the property because the intent of the parties at the time of contracting is controlling. Thus, parties who intend for a covenant to run with the land should not rely on a mere reference to the contract in a recorded instrument but should record the agreement itself, or some memorandum reciting the material terms, in the real property records and include express language in the agreement as to their intent for the covenants to run with the land.

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14349 Hits

Changes to the Operator’s Rights and Obligations under the New 2015 A.A.P.L. Model Form JOA

The American Association of Professional Landmen recently released its 2015 Model Form Operating Agreement. The A.A.P.L form 610 - Model Form Operating Agreement has established the operating framework within the United States since 1956, and the last major modifications to the Model Form occurred in 1989. The 2015 Model Form contains notable changes to provisions governing the appointment and removal of the Operator, access to records, assignments, authority of the Operator to communitize and pool, and the Operator’s standard of conduct. This summary is not comprehensive. There are many other substantive changes to the 2015 Model Form, including, but not limited to, changes related to horizontal drilling, which are not discussed in this summary.

Operator’s Standard of Conduct. The 2015 JOA revises the Operator’s standard of conduct. It now provides in pertinent part:

Operator shall conduct its activities under this agreement as a reasonably prudent operator, in a good and workmanlike manner, with due diligence and dispatch, in accordance with good oilfield practice, and in compliance with applicable law and regulations. However, in no event shall it have any liability as Operator to the other parties for losses sustained or liabilities incurred in connection with authorized or approved operations under this agreement except such as may result from gross negligence or willful misconduct. (Art. V.A, emphasis added)

Notably, the insulation of liability except for gross negligence or willful misconduct applies only to “authorized or approved operations” and not to all Operator activities such as accounting and other administrative functions. This is a significant change from the 1989 JOA form which broadly states that in no event shall Operator have “any liability as Operator to the other parties for losses sustained or liabilities incurred except such as may result from gross negligence or willful misconduct.” (Emphasis added.)

Non-Owning Operators. Article V of the 2015 Model Form maintains the general requirement that the Operator must own an interest in the Contract Area, except it allows the parties to decide the percentage of ownership the Operator must own and maintain and also allows a non-owning person to serve as Operator provided the putative non-owning operator and the Non-Operators enter into a separate agreement, or insert Article XVI provisions to the agreement to govern the relationship between them. Absent such separate agreement or Article XVI provisions, a non-owning operator shall be bound by all terms and conditions of the agreement applicable to Operator. Further, the failure of a non-owning operator and Non-Operators to enter into such a separate agreement or Article XVI provisions “shall disqualify said non-owning operator from serving as Operator, and a party owning an interest in the Contract Area must instead be designated as Operator.” Unless the parties have otherwise agreed, a non-owning Operator may also be removed at any time, with or without cause, by the affirmative vote of parties owning a majority interest. If good cause for removal of such non-owning Operator exists, the non-owning Operator may also be removed by the affirmative vote of Non-Operators owning a majority interest after excluding the voting interest of any non-operator who is an Affiliate of the non-owning Operator. Operatorship is “neither assignable nor forfeited” except in accordance with the provisions of Article V. The 2015 Model Form states that “a change of a corporate name or type of business entity” shall not be deemed to constitute resignation of Operator, but no longer includes the 1989 language that a “transfer of Operator’s interest to any single subsidiary, parent or successor corporation shall not be the basis for removal of Operator.” Whether courts will interpret this language to be a material change remains to be determined.

Removal of Operator. Article V.B.4 maintains the language in the 1989 JOA providing that an Operator may be removed for good cause by the affirmative vote of Non-Operators owning a majority interest after excluding the voting interest of Operator, and continues to provide that such vote is not effective until a written notice has been delivered to Operator by a Non-Operator detailing the alleged default and Operator has failed to cure within 30 days from its receipt of the notice (or 48 hours if the default concerns an operation then being conducted). The definition of “good cause,” however, is slightly broadened. The 1989 Form provides that good cause “shall mean not only gross negligence or willful misconduct but also the material breach of or inability to meet the standards of operations contained in Article V.A. or material failure or inability to perform its obligations under this agreement.” The new 2015 JOA form now states “good cause” shall “include, but not be limited to (i) Operator’s gross negligence or willful misconduct, (ii) the material breach of or inability to meet the standards of operation contained in Article V.A or (iii) material failure or inability to perform its obligations or duties under the agreement.” Art. V.B.4

Selection of Successor Operator. The 2015 Model Form generally maintains the 1989 Model Form provisions governing the selection of a successor Operator but clarifies that an assignee of the Operator’s interests is allowed to vote. Upon the resignation or removal of Operator, a successor Operator shall be selected by the affirmative vote of one or more parties owning a majority interest including the vote of the former Operator “and/or any transferee of the former Operator’s interest,” but if an Operator who has been removed or is deemed to have resigned fails to vote or votes only to succeed itself, the successor Operator shall be selected by the affirmative vote of the party or parties owning a majority interest remaining after excluding the voting interest of the Operator who was removed or resigned. The 2015 Model Form also includes a tie breaker provision: In the event of a tie, “the candidate supported by the former Operator or the majority of its transferee(s), shall become the successor Operator.” Art. V.B.6

Access to Records. Subject to certain exceptions, the 2015 Model Form provides that a Non-Consenting Party is not entitled to access the well and is not entitled to well information and reports solely relating to such non-consented operation until the earlier of full recoupment by the Consenting Parties or two years following the date the non-consented operation was commenced. Art. V.D.5. Prior to payout, however, a Non-Consenting Party who is not otherwise in default is generally entitled to review the joint account records pertaining to non-consented operations to the extent necessary to conduct an audit of the payout account. Under the 2015 Model Form, Operator is obligated to send “to the Consenting Parties” instead of “Non-Operators” (as used in the 1989 Model Form) such reports, test results and notices regarding the progress of operations on the well as the Consenting Parties may reasonably request, including daily drilling reports, completion reports and well logs. See Articles IV.A and V.D.5.

Operator Authority to Pool and Communitize. Article V.A and the Recording Supplement to the 2015 Model Form JOA now include provisions appointing the Operator as attorney-in-fact for executing declarations of pooling and communitization agreements on behalf of the Non-Operators. This provision eliminates some legal uncertainty related to whether an Operator can pool a lease in which it owns no interest (i.e., a lease owned by a Non-Operator), and addresses recent BLM actions which have denied communitization agreement proposals because not all the working interest owners signed the application.

Assignments. Article VIII.D of the 2015 Model Form JOA provides that, after expiration of a 30 day period, a transferor will not be liable for costs of operations conducted after that period. However, a recent Wyoming decision confirms the general rule that, with respect to those who are not parties to the JOA, the assignor remains liable under other contracts, such as leases or surface use agreements, absent an express novation or an agreement releasing the transferor of future liability upon assignment of interests.

Article VI. of the 2015 Model Form JOA also provides that any interests assigned to non-abandoning parties upon abandonment of a well by some but not all the owners will be made free of Subsequently Created Interests.

The 2015 Model Form JOA contains numerous other changes addressing horizontal drilling and other matters and should be carefully reviewed and modified depending on the intentions of the parties.

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Lessees and Operators Beware

In Pennaco Energy Inc. v. KD Company LLC, 2015 WL 7758324 (Wyo.) (“Pennaco I”), the Wyoming Supreme Court recently confirmed a precedent that subjects lessees and operators to liability for successors’ acts and failures under surface use agreements. At issue was the continued liability of Pennaco for obligations contained in a surface use agreement (“SUA”) entered into by Pennaco and the lessor. Under the terms of the SUA, Pennaco was obligated to make annual payments to the lessor and to reclaim the surface after wells are plugged and abandoned. Pennaco, having fulfilled all of its obligations while holding the lands subject to the SUA, assigned the lands and rights under the SUA to a successor, who then defaulted on these obligations and ultimately declared bankruptcy. In this suit to impose liability on Pennaco for its successor’s failures, the parties took widely different approaches as to what law should control obligations imposed in a SUA.

Using a colorful analogy, Pennaco likened its obligations to that of a football being passed from the quarterback to the receiver. Once Pennaco, as the quarterback, passed its obligations to its successor, KD Company, the successor held the obligations as the receiver would hold the football. Pennaco grounded its argument in property law, reasoning that its obligations were covenants running with the land, just as the SUA expressly provided that the benefits or rights received by Pennaco were covenants running with the mineral lease. In property law, covenants running with the land are obligations which are connected with an interest in land so that future owners of the interest will also have to fulfill them. Conversely, when an entity no longer owns the interest, that entity also no longer owes the obligation because it is connected with the interest, not the entity. Thus, once Pennaco assigned its lease and SUA interests to KD Company, under well-established property principles, Pennaco was no longer liable for these obligations.

In equally colorful language, KD Company likened the obligation imposed on Pennaco to a communicable disease. Just because Pennaco, the carrier of a disease, passed the disease to KD Company did not mean that Pennaco was cured. KD Company argued that established principles of contract law, rather than property law, controlled the issue. It reasoned that rights can be freely divested absent a contractual provision to the contrary, but a duty or obligation can only be divested with the approval of the party to whom the duty is owed. Thus, Pennaco would only be relieved of its contractual obligations if the SUA expressly released Pennaco from further liability upon assignment, or if Pennaco obtained a “novation” (the substitution of a new agreement for an old agreement, which could be in the form of an agreement with the surface owner to release Pennaco from those obligations). Because Pennaco had no such relief in this case, KD Company argued that Pennaco would still be liable under the SUA pursuant to contract law.

The Wyoming Supreme Court agreed with KD Company’s contract law approach, despite significant evidence that the obligations were intended to be covenants running with the land, including language that these covenants would run with the surface ownership. Instead, the Court reasoned that if the parties intended that the obligations, as well as rights, of the parties were to be covenants running with the land, they should have included language expressly stating that the obligations, like the rights, were also covenants running with the mineral estate. Thus, the Court held that while Pennaco’s rights ended upon assignment, its obligations continued because they were not covenants running with the mineral estate, and there was no express provision in the SUA relieving Pennaco of liability upon assignment.

Interestingly, the Court added a caution in dicta (authoritative language but not binding) in footnote 4, which reads in full: “By this analysis we do not determine that a clause stating Pennaco’s obligations were ‘covenants running with’ its mineral leases would have indicated intent that Pennaco was no longer responsible after assignment of the leases and agreements. An exculpatory clause must expressly terminate the assignor’s obligations upon assignment.” Emphasis added. With this language, the Court cautioned lessees and operators that they should not rely solely on the rules of property law to relieve them of liability in a SUA. Instead, they should insert express exculpatory language in the SUA to make it clear that they will be relieved of future liability after transferring their interest.

The Wyoming Supreme Court heard arguments in a related case on December 16, 2015 (“Pennaco II”). Pennaco has described Pennaco II, in its appellate brief, as presenting “the same/similar issue—under a different surface use agreement—as that presented” in Pennaco I. Prior to the argument in Pennaco II, Pennaco filed a motion for rehearing of Pennaco I. Pennaco therefore focused its oral argument in Pennaco II on why the Court’s decision in Pennaco I was wrong.

In response to questions from the judges, Pennaco also tried to distinguish the two cases by pointing to additional language in the Pennaco II SUA stating that the rights were covenants running with the land. However, one justice pointedly asked whether Pennaco believes that the surface owner knew and intended that Pennaco would be able to develop the minerals but then assign the lease and SUA shortly before the obligation to reclaim came due and thereby pass on the obligation. The facts of the case brought this concern to the forefront because Pennaco had given the surface owner assurances about reclamation in writing three weeks before assigning the lease and SUA to a small company that declared bankruptcy before reclaiming the surface. Thus, it appears likely that the outcome in Pennaco II will be the same as in Pennaco I. Pennaco could not point to any language in this SUA that relieves it of its obligations after the assignment, and the Court did not seem inclined to believe that the surface owner intended the SUA to allow Pennaco to do so.

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State or Local Control for Colorado?

In September, the Colorado Supreme Court agreed to hear two cases that have the potential to settle the state/local battle over fracking regulations. The conflict roots back to 2013, when voters in Longmont passed a ban on hydraulic fracturing, and Fort Collins passed a five-year moratorium. In response, the Colorado Oil and Gas Association (“COGA”) filed lawsuits challenging the ban and moratorium, arguing that they are illegal because case law and regulations give only the state the right to regulate drilling. The legal issue is “preemption” – when state and local laws conflict has the state “preempted” the area of oil and gas regulation invalidating local laws in conflict?

Local communities across the state have exerted limited control over oil and gas operations within their boundaries for decades under their “health, safety and welfare” authority. But, when it comes to the permissibility of fracking, which is essential to the majority of oil and gas development in the state, COGA asserts that Colorado’s state statutes and Colorado Oil and Gas Conservation Commission (“COGCC”) regulation should prevail. The COGCC estimates that more than 90% of the oil and gas wells in that state currently utilize fracking techniques. Indeed, fracking has permitted economic recovery of reserves that were previously too expensive to produce through traditional drilling techniques.

In response to COGA’s challenges, lower courts in Boulder and Larimer counties overturned the ban and the moratorium. Both courts found that the regulation of fracking is under control of COGCC, thereby preempting any local rules. Both cases moved into the Colorado Court of Appeals, where Longmont and Fort Collins asked to have the ban and moratorium restored. In a rare move, the Court of Appeals requested that the lawsuits bypass the intermediary court: “In light of the public interest in and the importance of the subject matter of these cases and of the legal issues implicated, they would seem to be cases as to which certiorari review by the Supreme Court is eminently appropriate.” On Wednesday, December 9, 2015 attorneys argued both cases in front of the Colorado Supreme Court.

The Colorado Supreme Court has already spoken on the preemptive scope of the Colorado Oil and Gas Conservation Act in a pair of decisions from the early 1990s: Voss v. Lundvall Bros., 830 P.2d 1061 (Colo. 1992); Bd. of Cnty. Comm’rs v. Bowen/Edwards Assocs., Inc., 830 P.2d 1045 (Colo. 1992). These decisions, and the preemption tests provided by each, proved to be the focus of both arguments. Longmont v. COGA, 15SC667, and Ft. Collins v. COGA, 15SC668, essentially differ only by type of regulation. The question for both boils down to what type of preemption analysis the courts must employ.

The cities argue operational conflict is the appropriate test:  Does the local regulation materially impede the efficient and economic production of oil and gas consistent with health, safety, and welfare of citizens? Using the operational conflict analysis, the Colorado Supreme Court in Bowen/Edwards Associates, held that the Colorado Oil and Gas Conservation Act, C.R.S. §34-60-101, et seq. did not entirely preempt a county from exercising its land use authority over any and all aspects of oil and gas development and operations in unincorporated areas.

At oral argument, the cities attempted to distinguish fracking from overall oil and gas operations, arguing that gas production can be achieved as efficiently by other methods including underbalanced production. The cities want the courts to apply the operational conflict analysis so that, on remand, the lower court will have to make certain factual conclusions about fracking including whether valid development alternatives exist.

COGA believes the defining case is Voss. Voss and its progeny set out Colorado’s implied preemption test for state/local regulation issues. There, the Colorado Supreme Court struck down a Greeley home rule ordinance completely banning oil and gas development within the city limits. The court determined that the ordinance was inconsistent with City and County of Denver v. State of Colorado, 788 P.2d 764 (Colo. 1990), which held that, in matters of mixed local and state concern, a home rule municipal ordinance could co-exist with a statute only so long as there was no conflict between the ordinance and the statute. The Voss Court noted that should there be such a conflict, it would be the state statute that would supersede the conflicting local ordinance.

The conflict described in Voss came before the Supreme Court in Colorado Min. Ass'n v. Bd. of County Com'rs of Summit County, 199 P.3d 718 (Colo. 2009). Facing a similar question on which preemption analysis applied, the Court held that Summit County's ordinance banning the use of cyanide or other chemicals in heap or vat leach mining operations for all zoning districts in the county was impliedly preempted by Mined Land Reclamation Act (“MLRA”). Because the general assembly had identified the field of chemical use in mining operations for mineral processing as a matter of significant and dominant state interest, and because the ordinance impeded MLRA's goal of encouraging mineral development while protecting human health and the environment, the court found it to be inconsistent with the general assembly's decision to authorize mining operations that use chemicals for extraction. Thus, the implied preemption analysis resolved the conflict between the MLRA and the ordinance in favor of the state law.

COGA emphasized Summit County at oral argument, analogizing the cyanide situation to the fracking cases in front of the Court, explaining that state statutes regulating an industry dominate when in conflict with local bans or limitations on “techniques” of the industry. As such, COGA argued that under the correct test of implied preemption, summary judgment is always the proper remedy and lower courts need not reach the facts of the case.

Ultimately, the dispute comes down to a supremacy battle involving the most significant energy innovation of the century. Colorado’s high court ruling on the cases will determine what preemption test applies, and consequently whether under certain facts local governments can limit or ban hydraulic fracturing rather than deferring to oil and gas regulation by the state agency.

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“Keep it in the Ground” – Part II

After the President denied the Keystone XL pipeline, climate change activists have turned their attention to federal fossil fuel leasing, discussed in our recent blog post: What’s Next, Post Keystone XL? “Keep it in the Ground!”.  The “Keep it in the Ground” proponents argue the President should abandon his “all of the above” energy policy for one that bans all future leasing of federal fossil fuels.

The argument has resulted in divided opinions—even within the Obama Administration. While Interior Secretary Sally Jewell has called the movement unrealistic and simplistic, EPA’s Administrator, Gina McCarthy, seemed to validate the environmentalists’ position by noting it would not be “extreme” for the government to ban all coal, oil, and natural gas production on federal lands.

Ultimately, for the Obama Administration, and future administrations, this policy argument raises a legal question: Could the Secretary of the Interior completely stop all federal coal and on and offshore oil and gas leasing? To answer that question, the Mineral Leasing Act of 1920 (“MLA”), as amended, the Federal Land Policy and Management Act (“FLPMA”) and the history of federal mineral management must be examined.

As Congress encouraged the settlement of the West, it began to take steps over time to retain management and ownership over federal minerals. Congress passed the Enlarged Homestead Act in 1909, 43 U.S.C. § 218, which allowed individuals to obtain title to up to 320 acre parcels without any reservation of the mineral estate to the government. In the subsequent Stock-Raising Homestead Act of 1916, Congress reserved “all coal and other minerals” to the federal government. 43 U.S.C. § 299; see also Watt v. Western Nuclear, Inc. 462 U.S. 36, 47 (1983) (observing Congress did not wish to entrust the development of valuable minerals to ranchers and farmers). Similarly, in the Coal Lands Acts of 1864 and 1873 the government conveyed lands without reserving the coal, but reversed course in later amendments in 1909 and 1910. The 19th and 20th century railroad acts also evolved from grants without reservation to surface-only grants.

In 1920, Congress enacted the Mineral Leasing Act of 1920, 30 U.S.C. § 181 et seq., to provide for more efficient development of federal oil, gas, and coal deposits. Section 226 of the MLA provides for leasing of oil and gas. Section 226(a) declares that “[a]ll lands subject to disposition under this [Act] which are known or believed to contain oil or gas deposits may be leased by the Secretary.” 30 U.S.C. § 226(a). The U.S. Supreme Court has found this language to provide the Secretary with discretionary authority to lease federal minerals. Udall v. Tallman, 380 U.S. 1, 4, (1965); see also Bob Marshall All. v. Hodel, 852 F.2d 1223, 1230 (9th Cir. 1988) (the MLA “allows the Secretary to lease such lands, but does not require him to do so.... [T]he Secretary has discretion to refuse to issue any lease at all on a given tract”). But does this secretarial authority to choose not to lease a particular parcel or tract of federal minerals extend to termination of the entire federal minerals leasing program? Such action does not appear to be the intent of Congress.

Congress enacted the MLA to “promote the orderly development of the oil and gas deposits in the publicly owned lands of the United States through private enterprise.” Harvey v. Udall, 384 F.2d 883, 885 (10th Cir. 1967). In California Co. v. Udall, the court stated that the Department of the Interior must administer the MLA “so as to provide some incentive for development.” 296 F.2d 384, 388 (D.C. Cir. 1961). The Mining and Minerals Policy Act of 1970, 30 U.S.C. § 21 et seq., emphasized the critical importance of federal mineral development and the essential role of the private sector and directed Interior to “foster private enterprise.”; see also Mountain States Legal Found. v. Andrus, 499 F. Supp. 282, 392 (D. Wyo. 1980) (“The Secretary of the Interior must administer the Mineral Leasing Act so as to provide some incentive for, and to promote the development of oil and gas deposits in all publicly-owned lands of the United States through private enterprise.”).

The Federal Onshore Oil and Gas Leasing Reform Act of 1987 amended the MLA to establish a competitive leasing system. 30 U.S.C. § 226(b)(1)(A). As amended, the MLA mandates the BLM to conduct lease sales “for each State where eligible lands are available at least quarterly and more frequently if the Secretary of the Interior determines such sales are necessary.” 30 U.S.C. § 226(b)(1).

“Keep it in the Ground” supporters argue that the Secretary could use the FLPMA land use planning authority to determine that no eligible lands are available in any state to effectively impose a nationwide moratorium on all new federal leasing. This argument ignores the above statutory mandates and overstates the Secretary’s limited authority to withdraw lands from leasing.

FLPMA established the federal policy to retain federal lands and to manage for multiple uses through the land use planning process to best meet national interests. 43 U.S.C. § 1701(a). FLPMA includes mineral development in its list of permitted multiple uses: “[T]he public lands [are to] be managed in a manner which recognizes the Nation’s need for domestic sources of minerals, food, timber, and fiber from the public lands . . .” Id. at (a)(12). Further, the Act requires that “the United States receive fair market value of the use of the public lands and their resources…” Id. at (a)(9). In this same section at (a)(4) Congress reserved its power to “exercise its constitutional authority to withdraw or otherwise designate or dedicate Federal lands for specified purposes and that Congress delineate the extent to which the Executive may withdraw lands without legislative action,” and specifically limited the Secretary’s withdrawal authority in size and to no longer than 20 years. 43 U.S.C. § 1717(d).

Read together, FLPMA’s management directives suggest that, at a minimum, a decision to withhold lands from leasing would need to be made on a site-specific basis through land use planning and that such withdrawal could not be made permanent without the authorization of Congress. See Norton v. S. Utah Wilderness All., 542 U.S. 55, 58 (2004) (explaining FLPMA’s multiple use mandate and noting lands not compatible with this mandate are identified by the Secretary on a site-specific basis as part of the land use planning process); see also Lujan v. Natl. Wildlife Fedn., 497 U.S. 871, 877 (1990) (discussing FLPMA’s direction that the Secretary “determine whether, and for how long, the continuation of the existing withdrawal of [selected] lands would be, in his judgment, consistent with the statutory objectives of the programs [other than multiple use] for which the lands were dedicated.”). FLPMA’s multiple use mandate—which includes mineral development— must be read in coordination with the MLA and the Mining and Minerals Policy Act. 43 U.S.C. § 1701(a)(12)(“including implementation of the Mining and Minerals Policy Act of 1970”).

As climate activists continue to press the government to transform federal leasing or simply keep federal fossil fuels in the ground, we can expect “policy forcing” litigation to follow. See, e.g., WildEarth Guardians v. Jewell, 738 F.3d 298, 312 (D.C. Cir. 2013) (rejecting the argument that BLM coal leasing in the Powder River Basin failed to properly consider global climate change); see also McKeown, Matthew J., “Emerging Clarity: Trends in Air Quality Litigation Arising from Federal Public Land Mineral Development,” vol. 58, ch. 25 (Rocky Mt. Min. L. Fdn. 2012). Courts and possibly Congress will be the ultimate arbiters of this movement giving a final word on whether the MLA, FLPMA, and the legislative history authorize the Secretary of the Interior to completely stop all federal coal and on and offshore oil and gas leasing.

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What’s Next, Post Keystone XL? “Keep it in the Ground!”

With the rejection of the Keystone XL pipeline by President Obama as part of the Administration’s “package” of climate change actions to deliver to the UN Conference on Climate Change in December, activists and their political allies have turned to the next battlefield – stopping the leasing of federal minerals. http://goo.gl/mU8qia

On November 4, Senator and presidential candidate Bernie Sanders (I-VT) and Senator Jeff Merkey (D-OR) introduced legislation to stop future federal oil and gas leasing in the Outer Continental Shelf and all federal leasing of onshore coal, oil, tar sands, gas and oil shale. The “Keep it in the Ground Act” also would prohibit the renewal of any “nonproducing” lease and cancel existing leases in federal waters off Alaska. See, S 2238, “To prohibit drilling in Outer Continental Shelf, to prohibit coal leases on federal land and for other purposes.” https://www.congress.gov/bill/114th-congress/senate-bill/2238

The President of the Natural Resources Defense Council ( and former Obama Interior Assistant Secretary) Rhea Suh applauded the legislation, “ Phasing out coal, gas and oil production in our federal lands and waters must be part of our broader strategy to shift from dirty fuels that drive climate change to clean energy.” Suh explained that, “Ending new leases for fossil fuels will prevent the release of 90% of potential emissions from federal fossil fuels. Federal lands and waters should be managed . . . to promote the rapid transition to the clean energy economy by keeping fossil fuels in the ground.” Bill McKibben, 350.org founder and anti-Keystone organizer, told Rolling Stone, “Effective action would require actually keeping most of the carbon the fossil fuel industry would like to burn safely in the soil.” The Center for Biological Diversity has led local “keep it in the ground” protests of BLM oil and gas lease sales in Wyoming and Colorado arguing federal fossil fuels represent 450 billion tons of carbon equivalent that should not be burned.

The movement, an offshoot of the fossil fuel divestment campaign, is informed by two studies that identified the potential GHG emissions from undeveloped fossil fuels. A study published in the journal Nature in January analyzed the question at a global scale and found that 80% of world coal reserves need to stay in the ground to avoid the “tipping point” of an elevation in global temperature of 2 degrees C. In the United States, The Wilderness Society and Center for American Progress retained Stratus Consulting in 2012 and 2014 to analyze the GHG emissions from extracting and burning federal fossil fuels. The 2014 update found that federal lands and waters “could have accounted for 24% of all energy-related GHG emissions in the United States in 2012” and “combustion of coal from federal lands accounts for more than 57% of all emissions from fossil-fuel production on federal lands.” See Center for American Progress (March 19, 2015). https://goo.gl/aPiMwJ .

At the end of September, Sierra Club, WildEarth Guardians, 350.org, EarthWorks among 400 environmental organizations presented a letter to President Obama calling on him to “keep federal fossil fuels in the ground.” The groups, citing the above reports, argue that federal leasing contributes “significantly” to U.S. and global GHG emissions and that under existing laws “you have the clear authority to stop new leases. With the stroke of a pen, you could take the bold action needed to stop new federal leasing of fossil fuels . . . .” An accompanying legal analysis argues that the Mineral Leasing Act, the Surface Mine Control and Reclamation Act, the Outer Continental Shelf Lands Act and the Federal Land Policy and Management Act grant considerable discretion to the Secretary of the Interior on whether to lease and that some of these acts grant the Secretary or the President the authority to withdraw lands from leasing. It is legally doubtful whether these acts would provide the authority to the Executive branch to cease all leasing of federal minerals which under the U.S. Constitution Article IV, Sec. 3 are under the plenary authority of Congress. Moreover in the Mineral Leasing Act (30 U.S.C, § 226(b)(1), Congress has directed quarterly lease sales and in the Mining and Mineral Policy Act of 1970 made clear that, “it is the continuing policy of the Federal Government in the national interest to foster and encourage private enterprise in (1) the development of economically sound and stable domestic mining, minerals, metal and mineral reclamation industries …” 30 U.S. C. § 21a.

While the “Keep it in the Ground Act” stands no chance of passage in this Congress, and Interior Secretary Jewell has rejected this approach has oversimplifying “a very complex situation to suggest we could simply cut off leasing or drilling on public lands and solve the issues of climate change,” she has embraced a suite of regulatory initiatives that environmentalists and their supporters have argued are part of this initiative. For example, in March in a major policy speech previewing BLM regulatory reforms, Secretary Jewell stated, “[W]e also need to do more to address the causes of climate change. Helping our nation cut carbon pollution should inform our decisions about where we develop, how we develop and what we develop.”

The Wilderness Society argues that a soon-to-be issued BLM rule to reduce venting and flaring and the already published draft revisions to Onshore Orders 3, 4 and 5 (https://goo.gl/2Dckrm and https://goo.gl/idRLrd ) to require the installation of meters on federal wells will help to limit GHG emissions from federal leasing. They also argue, and are joined in this argument by Democratic presidential candidate Hillary Clinton, that Interior should raise the royalty rates for coal and oil and gas to account for “the full costs of carbon pollution.” In June, Clinton called for “additional fees and royalties from fossil fuel extraction [to be used] to protect the environment.” Secretary Jewell announced a proposal to consider raising the royalty rate earlier this year. http://goo.gl/eKbNny And, the recently issued BLM resource management plan amendments for the Greater sage-grouse demonstrate the BLM’s willingness to use its FLPMA authority to withdraw millions of acres of federal minerals and limit the leasing of oil and gas for conservation purposes. Each of these requirements will incrementally “keep” a portion of federal fossil fuels “in the ground” which is the goal of that campaign.

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