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

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

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

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

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

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

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The Dakota Access Pipeline and What It Means

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

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

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

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

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

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

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

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

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

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

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Revisiting Proposed Initiatives 75 and 78 and Amendment 71

On August 29, 2016, Colorado Secretary of State Wayne Williams found that the proponents of Proposed Initiative 75 (Local Government Control of Oil and Gas Development) and Proposed Initiative 78 (Mandatory Setback from Oil and Gas Development) did not collect the requisite number of sufficient signatures to make the November ballot. Mr. Williams also provided a signature petition to Attorney General Cynthia Coffman after identifying a section that included potentially forged signature lines for investigation. While the defeat of Proposed Initiatives 75 and 78 was seen by many as the end of the fight between environmental groups and the oil and gas industry for the time being, the battle has continued in new arenas.

Undaunted, the representatives for environmental groups behind the proposed initiatives, Yes for Health and Safety Over Fracking, stated their intent to challenge the ruling. The proponents of the measure have thirty days from August 29, 2016 to appeal the decision to the Denver District Court by filing a protest under C.R.S. § 1-40-118(1) and (2). Any protest is limited to either contesting the verification process, including defects in the Secretary of State’s methodology, or fraud, abuse, or mistake in the petition process. If the protest is successful, and a defect in the Secretary of State’s methodology is discovered, all of the signatures will need to be counted and verified by hand. Should a line-by-line review become necessary, the Secretary of State’s Office will be under added scrutiny following controversy earlier this year surrounding the petition verification process for the Republican Senate primary ballot. As of today, there have been no reported protests filed, but some expect a challenge to be forthcoming prior to Thursday’s deadline.

In the meantime, the oil and gas industry and environmental groups have shifted their focus to Amendment 71, which would make amending the Colorado Constitution more difficult. Specifically, it would require at least 2% of the total certified ballot petition signatures come from each of the state’s 35 senate districts, and would require a 55% majority instead of the current 50% required. (For more information on Amendment 71, formerly known as Initiative 96, see the 8/31/2016 blog post).

Under Colorado law as it stands today, petitioning for a ballot initiative can be and often is limited to populous cities located on the front range, such as Denver and Boulder. Last week, the industry group Protect Colorado released an report analyzing the source of the signatures submitted for Proposed Initiative 78 (Mandatory Setback from Oil and Gas Development), where it was revealed that of the 77,109 signatures validated by the Secretary of State, approximately 70% were obtained from Denver, Larimer, and Boulder Counties. Boulder County alone accounted for nearly 25% of the signatures submitted. To the contrary, Weld County, which produces much of the state’s oil, and Garfield County, which produces much of the state’s natural gas, were greatly underrepresented in the petitions.

Colorado oil and gas industry groups support Amendment 71 primarily to limit the recurring battles, such as those in 2014 and 2016, over ballot initiatives concerning oil and gas development in Colorado, and also to providing a voice for Colorado voters in more rural areas who may not support more oil and gas initiatives. “Amending the state constitution should not be left solely in the hands of a few counties," Karen Crummy, communications director for Protect Colorado said. “The entire state should have a say on what does or does not make the ballot. Under Amendment 71, all Colorado voters would have a voice.” Interestingly enough, the restrictions set forth in Amendment 71 have made for some strange bedfellows, as it has been endorsed by a wide variety of organizations, from pork producers to marijuana advocacy groups.

Unsurprisingly, grassroots environmental organizers are opposed to Amendment 71, as they believe it would effectively prevent them from qualifying newer oil and gas initiatives for the ballot. They argue the cost of gathering signatures in all 35 districts will prevent progressive measures from reaching the ballot, and will extend the control of politicians and special interest groups, such as the oil and gas industry. Through Amendment 71 and the potential for protest of the petitions underlying Proposed Initiatives 75 and 78, the battle over oil and gas development in Colorado continues.

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The November Ballot Can Still Affect the Energy Industry

For those interested in Colorado’s energy economy, ballot initiatives concerning oil and gas regulation have rightly taken center stage. (See [4/27/16 blog post]). As of today, however, none of those public initiatives appear destined for the ballot this November.  The Colorado Secretary of State found that proponents of the two measures did not collect the requisite number of signatures to make the ballot. Though proponents turned in slightly more than the nearly 100,000 necessary signatures, the Secretary of State must conduct a random sampling of the signatures to assure that those signing are registered voters and the signatures authentic.  The Secretary concluded that both submitted measures lacked enough valid signatures, so they would not appear on the ballot (unless proponents successfully challenge the ruling).

But despite the fact that there will be no explicit challenge to the industry, another initiative could also significantly though indirectly affect regulation of the energy industry via initiative going forward. Initiative 96 would “raise the bar” - to quote the group promoting the measure - that must be cleared to amend the Colorado Constitution through the public initiative process.  If adopted by Colorado voters in November, it would become far more difficult for public initiatives and referendums, including those concerning energy regulation, to supplant or bypass the decisions of the General Assembly and, in this case, the Colorado Oil and Gas Conservation Commission.

Specifically, Initiative 96 targets the public constitutional amendment process in two ways.  First, it bolsters the signature requirements by requiring at least 2% of the total ballot signatures come from each of the state’s 35 senate districts.  This component appears to target the increasingly common practice of (often paid) signature collectors standing outside major events like games and concerts in metropolitan areas to generate signatures quickly and easily.  Proponents of the measure allege that such strategies leave rural districts with little input into the public ballot process.  Second, a constitutional amendment would require a 55% majority, not the 50% currently required.

Of course, these procedural changes would make it more difficult for the public to directly regulate the energy industry and, in turn, the state’s economy. As Governor Hickenlooper stated, Initiative 96 “is going to ensure that our constitution is not held captive by the whims of the day.”  Therefore, although it appears that the November 2016 ballot will not directly threaten radical change to the energy industry, the outcome of the election will still have a long-term impact on energy production and regulation in Colorado.

For some background on the use and management of the initiative process see “Citizen Initiatives: Power to the People or More of the Same?”, Rebecca W. Watson & Jennifer Cadena. http://goo.gl/z1zKSv

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Gold King Mine Spill Exposes the Legal Hurdles to Cleaning up Mines

This blog post was written by Katherine "Kate" Sanford who worked with WSMT as a summer intern from June 1 through August 10, 2016.

On August 5, 2015, Environmental Protection Agency (“EPA”) contractors inadvertently broke through a retaining wall at the closed Gold King Mine, causing over 3 million gallons of acidic, metal-laden water to flow into the Upper Animas Watershed in Southwest Colorado. The garish orange plume, which was estimated to contain around 900,000 pounds of heavy metals, made its way from Colorado, through New Mexico, and into Utah’s Lake Powell. Along the way, arsenic, lead, cadmium, copper, mercury, and zinc settled along the riverbeds of the San Juan and Animas Rivers. See Gold King Mine Accident Highlights Risks Posed by Abandoned Mines.

In the weeks and months that followed, downstream communities suffered from the spill: Durango rafting companies lost hundreds of thousands of dollars, and the Navajo Nation shut off two of its major irrigation systems, severing a lifeline for many farmers in the area. Meanwhile, the EPA took full responsibility for the disaster and worked quickly to build a $1.5 million dollar water treatment plant at the mine. Today, the water downstream is clear, but the cleanup is not over. The EPA has already spent $29 million in disaster response and may spend as much as $50 million before the task is complete.

Throughout the past year, the Gold King Mine spill has not only exposed the existence of abandoned mines that are leaking toxic water, but also the legal impediments to cleaning them up. There are an estimated 23,000 inactive mines in Colorado and 500,000 around the West. Federal investigators from the Department of Interior’s Bureau of Reclamation have found that tens of thousands of these abandoned mines are contributing to continuing pollution. But most of the companies that built the mines over the past 150 years have been out of business for so long that no one is around to take responsibility. To make matters worse, environmental statutes are hindering ”Good Samaritans” from mine clean-ups by burdening them with crippling legal liability. Consequently, the EPA is left with the expensive and arduous task of cleaning up almost all of them.

The Clean Water Act (“CWA”) is one example of a well-intentioned environmental law that poses a major hurdle to cleaning up abandoned mines. It affixes liability and responsibility to anyone who attempts to address a leaking mine, even if the owner had no role in creating the pollution and is working to clean it up. Similarly, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) imposes retroactive strict liability, meaning that current owners are liable even if the pollution was not their fault and even if the site was polluted before CERCLA was enacted. As a result, people are reluctant to try to clean up abandoned mining sites.

In the last year, several bills were introduced in Congress in response to the Gold King Mine spill to address these legal deterrents. Several of the bills are new versions of Good Samaritan legislation, which seek to reduce the liability of those who work to clean up abandoned mines. For example, senators from four different states introduced the Hardrock Mining Reform and Reclamation Act, which would reduce liability by amending the CWA so that Good Samaritans can obtain special permits. The Act would require mining companies to pay a 2% to 5% royalty for extracting mineral resources from public lands – a probable deal killer for an industry that pays no royalty. The Act would also create a reclamation fund to help pay for cleaning up abandoned mines. Similarly, the proposed Abandoned Mine Reclamation Safety Act would direct the Secretary of the Interior to create new regulations to facilitate the safe and environmentally responsible cleanup of abandoned mines.

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EPA Haze Rule – U.S. Court of Appeals for the 5th Circuit Stays EPA From Implementing Final Haze Rule in Texas and Oklahoma.

The federal Clean Air Act requires the states and the federal government to establish and meet targets for visibility in protected national parks and wildlife areas through regulations that control air pollutants in ambient air. 42 U.S.C. §§ 7410, 7491, 7492(e)(2). The federal government has the primary responsibility for identifying air pollutants and setting standards. The states, however, bear the primary responsibility for implementing those EPA standards by promulgating state implementation plans ("SIPs"). In accordance with the Act, the EPA issued a Regional Haze Rule in 1999 requiring states (1) to develop implementation plans by the end of 2007 for the 2009–2018 period and (2) to submit revised plans every ten years thereafter. 40 C.F.R. § 51.308(b), (f).

In January 2009, EPA found that Texas and Oklahoma (and several other states) had missed the 2007 deadline. Texas and Oklahoma subsequently submitted plans which were partially disapproved by EPA. In 2014, EPA proposed substitute federal plans and later issued its Final Rule in 2016. 81 Fed. Reg. 296 (Jan. 5, 2016). Claiming that the EPA was improperly targeting coal-fired power plants, the State of Texas, power plants, numerous energy companies, state regulators, and others filed a petition to review the Final Rule in the U.S. Court of Appeals for the 5th Circuit ("5th Circuit"). State of Texas v. U.S. Environmental Protection Agency, Case No. 16-60118. On July 15, 2016, the 5th Circuit issued an order denying EPA's motion to dismiss or transfer of venue of the petition, finding that:

• The 5th Circuit, which encompasses Texas, has jurisdiction to review the Final Rule pursuant to the Clean Air Act, 42 U.S.C. § 7607(b)(1);
• Venue in the 5th Circuit is proper because the petitioners' challenge addresses locally or regionally applicable action under the Act; and,
• Because staying implementation of the Final Rule was warranted, the 5th Circuit granted petitioners' motion for a stay pending resolution of the petitions for review on the   merits.

Because the EPA's actions involve 37 other states in other federal circuits, this matter may see inconsistent analyses by the several federal circuit courts and require final resolution by the U.S. Supreme Court.

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Wyoming Trespass Statutes Survive Constitutional Challenge

What do you do when someone enters your property to collect information about its status with the intent to convey that information to a governmental or regulatory agency without your permission? In Wyoming, you contact your local legislator.

In 2015, the Wyoming legislature enacted two statutes, Wyo. Stat. §§ 6-3-414 and 40-27-101 (the “Trespass Statutes”), in an attempt to regulate the issue of “Trespass to Collect Resource Data.” These statutes were deemed necessary to deter individuals from trespassing on private lands to collect resource data, because often those individuals could not be charged with trespass under the existing criminal statutes. Thus, the Trespass Statutes imposed criminal penalties and civil liability for the unauthorized collection or recording of information relating to land and land use, and the submission of that information to a governmental agency. The Western Watersheds Project, National Press Photographers Association, National Resource Defense Council, People for the Ethical Treatment of Animals and Center for Food Safety (collectively, the “Challengers”) challenged the constitutionality of Wyo. Stat. §§ 6-3-414 and 40-27-101 in the United States District Court for the District of Wyoming.

After briefing and oral argument, and a decision of the Court that questioned, in part, the constitutionality of the two statutes, the Wyoming legislature amended the statutes in 2016. As amended the statutes generally provide:

The revised statutes still define “resource data” as “data relating to land or land use, including but not limited to data regarding agriculture, minerals, geology, history, cultural artifacts, archeology, air, water, soil, conservation, habitat, vegetation or animal species,” … The new statutes clarify they apply only to entry onto private lands … and no longer require data be submitted or intended to be submitted to a governmental agency … [and] [t]he definition of “collect” has been modified to mean “to take a sample of material, acquire, gather, photograph or otherwise preserve information in any form and the recording of a legal description or geographical coordinates of the location of the collection.” (citations omitted)

See Order Granting Motion to Dismiss dated July 6, 2016 (D. Wyo.) at p. 5. After the 2016 amendments, the Challengers amended their complaint to challenge the constitutionality of the amended statutes. However, the Court dismissed.

In summarizing its holding, the Court notes “[Challenger’s] First Amendment right to create speech [by gathering resource data] does not carry with it an exemption from other principles of law, or the legal rights of others.” Order at p. 13. Specifically, “[Challenger’s] desire to access certain information, no matter how important or sacrosanct they believe the information to be, does not compel a private landowner to yield his property rights and right to privacy.” Id. “The ends, no matter how critical or important to a public concern, do not justify the means, violating private property rights.” Order at p. 26.

The Challengers have yet to determine if they will appeal the Court’s decision. So, for now, the Court’s Order stands and both Wyo. Stat. §§ 6-3-414 and 40-27-101 remain the “law of the land.” The District Court’s Order can be accessed on its website at http://www.wyd.uscourts.gov/htmlpages/docs.html.

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Bears Ears . . . What Does it All Mean?

Last week, Natural Resources Chairman Rob Bishop (R-Utah), formally introduced his revamped House Bill, the Public Lands Initiative, which seeks to designate millions of acres of proposed Wilderness, establish large motorized recreation areas, and expedite the development of oil, gas and minerals in southeastern Utah. The Bill encompasses the controversial Bears Ears, a pair of buttes located in San Juan County, Utah. Bordered on the west by Dark Canyon Wilderness and Beef Basin, on the east by Comb Ridge and on the north by Indian Creek and Canyonlands National Park, the Bears Ears are named for their resemblance to the ears of a bear emerging from the horizon. Various American Indian cultural legends and history stories incorporate the Bears Ears into their lore. Bishop initially introduced the Public Lands Initiative legislation in January but, due to its failed initial reception, the Bill has undergone various changes in the intervening months.

Bishop’s draft legislation from January would have protected 4.3 million acres, including 2.2 million acres of wilderness, in seven counties: San Juan, Grand, Emery, Carbon, Uintah, Duchesne and Summit. The original plan included a conservation designation of 1.1 million acres around the Bears Ears buttes. The new legislation increases the designation to 1.4 million acres of the now proposed 4.6 million acre region as a national conservation area surrounding Bears Ears, but leaves more lands available for multiple uses. The Bill would transfer all federally-owned energy and mineral resources in the southern Utah area to state control, paving the way for new uranium, coal, and oil extraction.

In addition to granting the State of Utah unilateral control over federal energy and minerals across southern Utah, Bishop’s Bill would open Recapture Canyon, one of many areas in the region rich in Native American sacred sites, to motorized vehicles, fulfilling an objective of anti-federal government activists who staged an armed takeover of the area in 2014 under the direction of Cliven Bundy.

Although the Bill seeks to establish use designations and expand certain protections to these federal lands, Bishop has openly and strongly argued against designation of Bears Ears as a National Monument. Meanwhile, the Inter-Tribal Coalition, a five-tribe organization made up of the Hopi Tribe, Navajo Nation, Ute Mountain Ute Tribe, Pueblo of Zuni, and Ute Indian Tribe, is pushing for National Monument protections of the Bears Ears region within Bishop’s Bill. The leaders of the Inter-Tribal Coalition, who walked away from talks with Bishop last December, disapprove of the latest version of Bears Ears protections contained within his revised Bill, released July 14, 2016, and instead are lobbying President Obama to designate a 1.9 million acre section of the land as “Bears Ears National Monument.”

As discussed in a prior WSMT blog post, the path to National Monument designation and protection began in 1906, when Congress passed the Antiquities Act in response to looting and grave-robbing taking place in the Four Corners region, at places like Mesa Verde, Colorado (which is now a World Heritage Site as well). The Antiquities Act grants the President authority to designate National Monuments in order to protect “objects of historic or scientific interest.” The full extent of presidential authority came to light after President Clinton’s surprise proclamation establishing the Grand Staircase-Escalante National Monument in 1996 led Utah counties to sue, arguing that the Antiquities Act violates the Constitution by usurping Congress’s power to manage federal lands. However, the Tenth Circuit Court of Appeals ultimately sided with the White House, holding that courts lack authority to determine whether the President abused his discretion in designating a National Monument. The result is that a president’s power under the Antiquities Act is effectively unlimited. Indeed, the Grand Staircase Escalante decision continues to shape the politics of public lands, frustrating critics of the Antiquities Act.

Clinton’s designations set a template for the Obama Administration which has approached the designation of National Monuments as a way to bolster safeguards for the country’s national treasures. In the case of Bears Ears, those in favor of National Monument designation, including the Inter-Tribal Coalition, assert that the area is imperiled by the kind of looting and pillaging that first inspired the Antiquities Act, as well as the modern threat of unrestricted ATVs ripping through the desert terrain.

Opponents disagree with the need for National Monument designation. Bishop has heard their concerns and, in response, undertaken a swift effort to develop a Bill that maintains balance. His Bill establishes areas outside of the proposed Wilderness as “energy zones” to foster development of oil and gas, coal, and other minerals—important economic staples for Utah. In part, Bishop and his fellow critics look at the Grand Staircase-Escalante decision as a symbol of federal power run amok. Because Clinton carried out the designation in near-total secrecy, it seeded distrust and resentment among state officials. Moreover, critics blasted Clinton for locking up potential for development of the encompassed massive coal deposit and turning the region into a vast playground for Easterners—concerns that hit close to home for opponents of the Bears Ears National Monument. On the other hand, conservationists maintained that protecting Grand Staircase-Escalante was a key step in leveraging the recreational value of BLM lands. Negative reaction in the days following the announcement of Bishop’s redrafted Bill confirms that the Bill is insufficient to bring the contrasting objectives of mineral development and conservation into agreement.

While Utah is already widely known for its spectacular outdoor recreation opportunities at treasured destinations and recreation havens—including, for example, Arches National Park, Dinosaur National Monument, Zion National Park—Bears Ears would add another gem. The state’s public lands bring in dollars from residents, as well as out-of-state and international visitors. According to the Outdoor Industry Association Utah generates $12 billion in consumer spending and $3.6 billion in wages and salaries related to outdoor recreation, no small impact on the state’s economy (and, for that matter, the national economy too).

An important piece of the proposed legislation is the separate and distinct use designations which specifically includes areas that permit motorized recreation, a wildly popular activity in Utah. But there will also be plenty of hiking, biking and other opportunities to appreciate this unique area. Regardless of final form, the Bears Ears Public Lands Initiative Legislation will continue to provide outdoor recreation opportunities in Utah.

Due to the magnitude and complexity of the Bill, Bishop expects it to get a vote this fall after further hearings and committee vetting. However, a National Monument designation may already be a done deal in the eyes of the Obama Administration. Secretary of the Interior Sally Jewell visited the area in the days surrounding Bishop’s announcement of the revised Bill. While her attendance doesn’t necessarily mean a monument decision is imminent, other such visits have foreshadowed National Monument designations.

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

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

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

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

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

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Supreme Court Grants Operational Flexibility to Owners of Multiple Conditional Water Rights

The Colorado Supreme Court’s recent ruling in Upper Eagle Reg'l Water Authority v. Wolfe, 2016 CO 42 creates opportunities for owners of more than one conditional water right to make those rights absolute in advance of demonstrating the need for both, and the “catch” or court-imposed limitation may not have a practical effect in some situations.

In Upper Eagle, the applicant owned a junior and a senior conditional water right for diversion and use at the same location and for the same purpose. The conditional rights were granted for projected future need. Presently, the applicant needs less than what one of those rights can provide. At a time when both rights were in priority and the applicant diverted what it needed, the applicant chose to attribute the diversion to the junior conditional water right. It thereafter sought to make that part of the junior right absolute.

The Court allowed this, and it held “that where there is no evidence of waste, hoarding, or other mischief, and no injury to the rights of other water users, the owner of a portfolio of water rights is entitled to select which of its different, in-priority conditional water rights it wishes to first divert and make absolute. However, the portfolio owner must live with its choice.” Id. at ¶ 2.

The Court rejected the argument that this would allow owners of several conditional water rights to make all of them absolute before there is a need for, and availability of, the total combined amount of water. The Court stated that the “catch,” when choosing to attribute a diversion to the junior conditional right, is that then the owner can no longer divert pursuant to the senior conditional right without showing a need therefor above and beyond what can be diverted through the junior right. Id. at ¶ 21. The Court seemingly believed that this would effectively prevent the owner from diverting pursuant to the senior right until it has a need for more than the full amount of the junior right.

That is, however, not necessarily the case. As an example, assume that Owner has a junior and a senior water right for 1 c.f.s. each based on a projected future need for 2 c.f.s. For now, Owner’s need is limited to 1 c.f.s. Under the rule announced in this case, Owner can apparently attribute a 1 c.f.s. diversion on a day where both rights are in priority due to extraordinary rainfall to the junior right and thereby make it absolute. The following day, when the rain has stopped and the junior right is out of priority, but the senior right is in priority and needed, the Owner can then make the senior right absolute as well. That is so regardless of the fact that Owner never needed or diverted more than 1 c.f.s.

The Court failed to recognize that changing river conditions can potentially create a legitimate need for the senior right before there is a need for more water than could be diverted pursuant to the junior right had it been in priority. Upper Eagle, therefore, provides an opportunity for those who own several conditional water rights that can be diverted at the same point for the same use to make their rights absolute long before reaching their projected need.

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BLM Fracking Rule Dead—For Now

It was an interesting week for BLM’s hydraulic fracturing rule first finalized and then immediately challenged on March 26, 2015. On Monday (June 20, 2016), the BLM filed its final brief in the Tenth Circuit arguing that the Wyoming Federal District Court erred when it issued a nationwide injunction of the rule on September 30, 2015. On Tuesday (June 21, 2016), the Wyoming Federal District Court set aside the BLM’s fracking rule, finding "The BLM has attempted an end-run around the 2005 EPAct; however, regulation of an activity must be by congressional authority, not administrative fiat.”

The central question the court addressed was did Congress give BLM the authority to regulate fracking?

In addressing this question, the court examined the broad management authority granted to BLM/Interior in the several statutes relied on by BLM – Mineral Leasing Act (MLA), Federal Land Policy and Management Act (FLPMA) and two Indian mineral statutes—and then analyzed the more narrow authority granted to EPA in the Safe Drinking Water Act (SDWA) to regulate underground injections into drinking water and the specific exemption from the SDWA for non-diesel hydraulic fracturing in the Energy Policy Act of 2005 (EPAct 2005). Judge Skavdahl concluded that neither the MLA nor FLPMA give BLM specific authority to regulate fracking and that, further, neither statute gives BLM environmental regulatory authority.

In examining the MLA, the court found the statute was focused on protecting oil and gas formations—not groundwater— and “surface-disturbing” activities—not downhole activities. The court also rejected BLM’s argument that fracking falls directly within its “regulatory sphere” and that the Bureau had long-regulated fracking. “BLM’s only regulation addressing hydraulic fracturing worked to prevent any additional surface disturbance and impose reporting requirements and did not regulate the fracturing process itself.” The court next examined FLPMA and concluded the statute is a land use planning law and not an environmental law. “Congress delegated regulatory authority for environmental protection of underground water sources to the [EPA], not the BLM.”

Finally, the court looked to SDWA and EPAct 2005. CRS Report on SDWA/fracking. The court determined it was clear that “Congress intended to remove hydraulic fracturing operations (not involving diesel fuels) from EPA regulation under the SDWA’s UIC program.” The court’s decision to invalidate BLM’s fracking rule rested on the rationale that “it makes no sense to interpret the more general authority granted by the MLA and FLPMA as providing the BLM authority to regulate fracking when Congress has directly spoken to the ‘topic at hand’ in the 2005 EPAct.”

The decision is widely expected to be appealed by the BLM and the environmental group intervenors have already declared they will appeal. The BLM’s Tenth Circuit brief on overturning the preliminary injunction of the fracking rule is a likely preview of what those arguments will be. BLM understandably argues that the MLA and FLPMA have been read too narrowly by the court and that, rather, these federal statutes contain “capacious delegations” to BLM to regulate “all operations on federal leases.” BLM adds that, “FLPMA further enhances BLM’s authority to protect natural resources and the environment” and that authority is not limited to planning. Finally, in addressing the crux of the court’s analysis that the SDWA and the EPAct 2005 non-diesel fracking exemption are evidence of a congressional decision to exclude BLM from the regulation of fracking, the government points to legislative history of the SDWA that states, “The committee intends . . . that EPA will not duplicate efforts of the USGS [BLM’s regulatory predecessor] to prevent groundwater contamination under the Mineral Leasing Act.”  Good discussion of legal issues on appeal.

The government has 60 days to file an appeal, but given the importance of this rule, don’t be surprised if an appeal is filed in advance of 60 days.

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LOOK OUT! A COLORADO COURT FINDS THAT A MINERAL RESERVATION IN THE HABENDUM CLAUSE OF A DEED, NOT THE GRANTING CLAUSE, IS A VALID RESERVATION

An old rule of thumb for title examiners was that a mineral reservation needs to be in the granting clause, not the warranty clause, of a deed to be valid. As the courts have moved to seeking to determine the parties’ intent in a deed, these old rules have been whittled away. A recent Colorado Court of Appeals case shows that a title examiner needs to read the entire deed and that a mineral reservation does not need to be in the granting clause to be valid.

In Owens v. Tergeson, 2015 COA 164, 2015 WL 6746535 (2015), the court of appeals interpreted two deeds from 1950 and found that all oil, gas and other mineral interests were reserved in the deeds.

The reservation was not in the granting clause of the deeds. The court found the reservation was in the habendum clause of the deeds (the clause that starts out “To Have and To Hold . . . ”). The part of the deeds where the reservation was inserted read:

. . . free and clear from all former and other grants, bargains, sales, liens, taxes, assessments and encumbrances of whatever kind or nature soever. except reserving all oil, gas and other minerals and the right to use so much of the surface as is necessary to develop, produce and care for the same; also 1950 taxes; and the above bargained premises in the quiet and peaceable possession of the said party of the second part, his heirs and assigns against all and every person or persons lawfully claiming or to claim the whole or any part thereof, the said parties of the first part shall and will WARRANT AND FOREVER DEFEND.

The court of appeals found it was important that the deeds appear to be a printed form of warranty deed with the reservation language added.

The court noted that in a 1952 case, the Colorado Supreme Court rejected the old common law rule requiring the reservation to be in the granting clause, in favor of the more modern view that the overall intent from the deed considered as a whole should control.

This decision is interesting to title attorneys because it confirms the trend of the court to interpret deeds as a whole to determine the parties’ intent.

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Thoughts on Non-Administered Arbitration

Non-administered arbitration (“NAA”) is an informal dispute resolution process designed to proceed without the involvement of a separate administering entity. The arbitrator and parties administer the proceedings.

The proceedings may be guided by a procedure the parties define, or the parties may agree to use institutional rules and procedures such as Rules for Non-Administered Arbitration published by the International Institute for “alternative” Conflict Prevention and Resolution (“CPR”). The objective is a dispute resolution process that is truly alternative – more efficient, flexible and expeditious than both adversarial litigation and formal administered arbitration.

I was recently an arbitrator in an NAA proceeding under the CPR Rules. This posting provides some of my reactions.

Avoid litigation in disguise

The effectiveness of the NAA alternative is only as good as the joint effort of all participants – the parties, their representatives and the arbitrator. Everyone involved in a non-administered arbitration proceeding must share the objective and make certain that the speed, flexibility and efficiency that the NAA process offers are realized and that the proceeding doesn’t devolve into litigation in disguise.

Parties who agree contractually to resolve their disputes in an NAA process seek a non-appealable, binding, just and fair result. That’s the low hanging fruit. Those contracting parties also deserve fruit higher up the tree – they deserve a dispute resolution proceeding that is focused, flexible, and less costly and time-consuming than formal administered arbitration or litigation. Everyone involved has an obligation to work to that end.

The approach

An important factor in meeting that obligation is how each participant approaches the NAA proceeding. Helena Tavares Erickson, a Senior Vice President at CPR, published an article on point some time ago (2006). Among her several valuable messages is the view that those involved must approach the dispute “as a problem to be solved, not a contest to be won.”

I agree. Contests to win are more expensive, more time consuming and less controllable than joint problem solving efforts. The benefits of an NAA proceeding are best realized in a problem solving context.

The schedule – agree and stick to it

As soon as the parties acknowledge the existence of a dispute to be arbitrated under NAA rules, they engage a mutually acceptable arbitrator. Then all concerned, including the arbitrator, should quickly (within days, not weeks or months) confer and agree to a date for a substantive hearing on the issues. This date should be written in stone, i.e., should be changed only (i) due to force majeure events and (ii) if and when not changing the date would mean genuine prejudice to a party.

The date should be realistic in terms of time needed for preparation. The original agreement which calls for dispute arbitration may provide unrealistic timing, e.g., 60 days to select and appoint an arbitrator and get to hearing on complicated factual/legal matters. It’s fine to override that prior agreement in the face of an actual dispute.

What shouldn’t be overridden is the clear intent of the parties to have the dispute heard and resolved quickly. Not getting to a substantive hearing on the merits of the dispute many months or more after arbitrator appointment is not the expeditious, economical dispute resolution process the parties originally bargained for.

Core issues – early identification and focus

Identification of the core issues in dispute, and early focus on those issues, can and should happen in arbitration, especially NAA. The flexibility to make this happen is a major advantage of the NAA process.

To get there, the parties and their representatives need to find the courage to work together to prioritize the factual and legal issues that comprise the dispute. This makes it possible to bring these core issues to the arbitrator for preliminary, non-binding review, or perhaps even for formal determination. Either way, the expertise of the arbitrator, the primary reason he/she was retained, is taken advantage of early on, and the possibility of mediation, or even settlement, of the entire dispute is increased.

If the parties and their representatives are reluctant to single out core issues for early scrutiny, the arbitrator should be ready to encourage them in that direction. The arbitrator needs to be sensitive to the time/cost value of bringing his/her expertise into the dispute in a constructive way early on.

This preliminary issue review requires two things:

1. Confidence on the part of the arbitrator -- the ability to express a high level opinion (make a call) based on the experience and expertise that he/she is bringing to the table without first having to see every possible bit of data or hear every possible legal argument.
2. Parties and party representatives who are willing to listen and act on the arbitrator’s early stage opinion regardless of whether they agree that this preliminary arbitrator opinion is binding.

Atmosphere – informal, open

This is a challenge, especially for lawyers trained in the courtroom. I’m not suggesting that everyone arrive at each session in blue jeans and flip-flops. I am suggesting that the participants strive for an atmosphere that is conducive to problem solving, that fosters professionalism as well as mutual respect and friendliness, and that leaves room for important openness and listening.

For the parties and their representatives, this requires:

• Self-control in terms of what each participant brings to the table,
• Fewer motions and objections in response to what has been put on the table,
• The courage to make their own conscience-guided determinations of what is truly relevant and helpful to the effort, and
• Confidence that the arbitrator is good enough not to need formal motions in order to see every weakness in what has been presented.

For the arbitrator, this is about not letting evidentiary issues get in the way. Let your experience, judgment and expertise (the qualities that brought you to this proceeding in the first place) tell you what you don’t need to know or listen to in order to do your job.

The record – do we need one?

The reasons for making a record in a formal dispute resolution proceeding don’t exist in an NAA proceeding. There won’t be an appeal on the merits of the final award, so that’s not a reason. Preserving a possible challenge to the final award based on arbitrator conflict or bias is also not a valid reason for a record. The potential for such a challenge should be raised and resolved long before the proceeding commences. That leaves the possible need for a record for reference purposes for final briefing and arguments to the arbitrator, and the making of the record can be tailored to that need.

So, this is not to advocate that NAA proceedings not be recorded. I am suggesting that the participants first work together to determine why a record is needed. They should then tailor the making of the record to the identified need before engaging in the expense and the additional logistics of making a record of all evidentiary presentations.

CPR is a leading NAA advocate. Their website is a valuable tool for those interested.

In summary

To repeat –

  1.      • The benefits of an NAA proceeding are best realized in a flexible, problem solving context.
         • The judicial process, the formal administered arbitration process, and all of the evidentiary and other rules and procedures that go along with those processes, are designed for          win-lose contests. They don’t allow for the flexibility that is an important benefit of an NAA proceeding, and they cost money and consume time.
         • Participants (parties, representatives and arbitrators) who are committed to the expediency and effectiveness of the NAA process must avoid engaging in litigation in disguise.            They should welcome and take full advantage of the flexibility that comes from working together to solve a problem.
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Mission Assurance is Energy Assurance*

* This blog is co-authored with Sarah Ruckriegle, a graduate of the Air Force Academy, current Captain in the Air Force and law student at the University of Las Vegas where she is based.  Heidi Ruckriegle is an Associate with the Welborn firm.  

The United States Department of Defense (“DoD”) is the world’s single largest user of fossil fuels. DoD is comprised of three branches—Air Force, Army, and Navy—and reliable, affordable, and available energy is critical to each of their missions. The military spends $4 billion dollars a year to meet its energy needs and two-thirds of that energy is petroleum. Of the branches, the Air Force is responsible for using more than 2.4 billion gallons of jet fuel annually, making it the highest energy consumer. By contrast, the Navy uses roughly 1.3 billion gallons of fuel annually. The Army consumes much less energy because of its reliance on the Air Force and the Navy for transportation. The Army’s energy use is concentrated in its installations, which consume an average of 661.5 million gallons of petroleum each year.

DoD has identified its oil supply chain to the military’s land, water, and air equipment as a point of vulnerability. Aerial refueling and convoys transporting fuel can be extremely dangerous. In its 2011 Strategic Sustainability Performance Plan, DoD wrote “attacks on fuel convoys and fixed energy supplies in Afghanistan, Iraq and surrounding countries already demonstrate the vulnerability of our current supply networks.” A 2009 Army Environmental Policy Institute report shows that between 2003 and 2007 approximately 50% of more than 3,000 U.S. troops and contractor deaths or injuries were attributable to fuel supply convoys in Afghanistan and Iraq. To reduce dependence on supply chains and oil, the military is broadening the use of solar and other renewable sources in meeting its defense mission.

The move to renewables will also help DoD meet new national directives to conserve energy and increase the use of renewable energy:

• the Energy Independence and Security Act of 2007 requiring federal agencies to improve energy intensity by 30% as compared with 2003 baseline;
• the National Defense Authorization Act of 2007 mandating DoD secure 25% of its energy from renewable resources by 2025; and
• Executive Order 13514 issued by President Obama on Oct 5, 2009, directing federal agencies to develop and implement an annual Strategic Sustainability Performance   Plan to the Council on Environmental Quality between 2011 and 2021 and ensure federal buildings designed in 2020 or later are net zero for energy, i.e., not using more   energy than they produce, by 2030.

Further, in enhancing its renewable energy portfolio, DoD is also responding to two emerging threats to its operations around the world: climate change and cyberterrorism. Internal studies have documented the military’s vulnerability to disruptions to the power supply from cyber attacks and long-term impacts from global warming. In many parts of the world, DoD looks at global warming as a “threat multiplier,” meaning that increased pressure from progressively more severe weather is expected to exacerbate economic and political issues. Similarly, DoD is vulnerable in our wired, internet-centered, world. The April 2015 DoD Cyber Strategy focuses on building capabilities for effective cybersecurity and cyber operations to defend DoD networks, systems, and information.

The military’s ability to employ a defense force, execute a mission, or train for the future, is heavily dependent on fuel and the electricity that powers installations and operations. The various branches have identified “energy resilience” as a critical objective. The Army developed innovative private-sector funding of solar installations, a successful program that later launched the Office of Energy Initiatives in 2011. In turn, the Air Force has set the standard for utility-scale solar with its 14 megawatt giant in 2007, called “Nellis I” after its Air Force Base home. Nellis Air Force Base opened a second major solar array in February of this year. Seeking to strengthen alternative energy, the Navy has an ambitious goal of getting 50 percent of its energy from renewable sources by 2020, while the Air Force and Army maintain more modest goals of 25 percent.

Solar maintains its position as the renewable resource of choice at military installations because tall wind turbines create the potential for collision danger to military aircraft operations and generate “clutter” from close-by wind turbine projects impacting airborne military radar capability. The hazards to air safety and surveillance presented by wind energy are unacceptable to DoD. However, as DoD continues to enhance its energy portfolio, geothermal and biomass have gained more recognition as possible alternatives. Each of the armed services has also established programs geared toward alternative fuel to replace petroleum in their tactical weapons systems such as aircraft, combat ships and vehicles, and supporting equipment. DoD currently uses gasohol and biodiesel in administrative and other nondeployable vehicles but continues to evaluate and test other alternative fuels (e.g., hydrotreated renewable oils, coal-derived or algae-derived fuels) for military applications. Considerations include whether the alternative fuel is cost-competitive, performance consistent, and emitting fewer greenhouse gasses.

On April 6, 2016, the Army and Air Force signed a Memorandum of Understanding confirming a common commitment to securing military installations with energy that is clean, reliable, and affordable. Large-scale renewable projects at military installations independent from the grid can keep the lights on in the event there is a cyber attack or severe weather event that knocks out power. Renewable energy projects located on or near military bases are vital to keeping missions and operations fully functional at a time when the Armed Services are increasingly reliant on electricity to keep the country safe.

The Air Force is aware that its global role and presence has changed; it needs guaranteed power for remotely piloted aircraft missions, missile launches, space launches, and satellite control. With new remote-controlled technologies, the Air Force has been fighting more battles from domestic bases—as a result installation energy security is even more important. Looking forward, the Air Force believes that in order to build resiliency its budget is better spent on renewable projects that cost less than traditional grid energy. Beyond domestic bases, the Air Force is also working on ways to improve energy reliability for its expeditionary forces by developing modernized equipment using solar panels and batteries rather than the expensive and dangerous conventional convoys or airdrops of fuel supplies.

DoD’s development of renewable energy is viewed by the agency as necessary but has faced some criticism on the Hill from renewable energy skeptics. Disagreements exist as to whether the DoD's efforts to move to renewable energy are more about politics than saving lives and boosting security. Among lawmakers' complaints is concern that the military is paying a higher price for some forms of renewable energy at a time when DoD proposes cutting weapons programs and reducing forces in order to meet budget mandates. DoD officials insist that their efforts focus on a single goal: finding the best way to power military missions.

National security will always be the Unites State’s top priority. In the words of George Washington, “to be prepared for war is one of the most effectual means of preserving peace.” How renewable energy will play a role in DoD strategy is just beginning to take shape.

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Colorado Supreme Court Applies Strict Burden of Proof of Historical Use for Change of Water Rights

In late March, the Colorado Supreme Court ruled in County of Boulder v. Boulder & Weld County Ditch Co., 367 P.3d 1179 (Colo. 2016). While this case did not involve any novel questions of Colorado water law, it did provide a clear warning to applicants for changes of water rights that they must be prepared to demonstrate detailed evidence of historical beneficial use, even in very complicated situations, for their claims to be approved.

This case involved an application by Boulder County to change water rights from an irrigation ditch for use to augment groundwater depletions from gravel pit ponds to support an open space park development. The ditch at issue carried a very senior priority of 1861, and had been decreed to irrigate 120 acres. However, the original decree did not identify which 120 acres could be irrigated. The water right for the ditch had long since been divided into fractional ownership, quantified as 185 “inches” (a commonly used method to divide a flow rate into smaller interests). Boulder County owned 100 inches, and other owners held the remaining 85 inches.

The Division 1 Water Court denied Boulder County’s application, holding that the County failed to prove the extent of historical use of the water right. The water court also held that the County should have conducted a “ditch-wide” historical use analysis, rather than a parcel-specific analysis, because the County’s approach would have resulted in the County obtaining credit for almost all of the decreed water right, even though several other owners also owned fractional interests in water right.

In Colorado, water rights are decreed for specific places and purposes of use. If an owner of a water right wishes to change that water right for use at another location or for a different use, the applicant must apply for approval from the water court. In order to ensure that the water right is not enlarged to the detriment of other water users, the court will quantify the water right based on actual historical beneficial use. Often, this results in a significant reduction in the annual amount of a water right, from the original decreed limits. Therefore, applicants must conduct a detailed historical use analysis, in order to make their best case regarding the amount of the water right that should be carried forward for a new use. In some cases, it is very difficult to reconstruct the use of a water right over many past decades. Often, the original users of the water are no longer alive. Applicants must resort to field notes from state water administration officials, written statements from the former users, if they exist, aerial photographs, and interviews of neighboring landowners in order to reconstruct the historical use of the water as best they can.

The murky history of the water right at issue in Boulder County v. Boulder & Weld County Ditch Co. led to the water court’s denial of the application, and the Supreme Court affirmed that ruling. The applicant had not proven to the satisfaction of the court just how much of its water right had actually been used on one of the claimed places of use. Other water rights had also been used on that farm, and there was no direct evidence that this specific water right had actually been used there, even though it had been delivered to the landowner’s headgate. Also, the court was unconvinced that the County had not overestimated its historical use of the water right for a 22 year period, from 1950 to 1972. The court found that the historical water delivery records from 1973 to 2000 were accurately calculated, but that was not good enough. There were no delivery records for the earlier 22 year period, and the applicant was not entitled to an assumption that it had taken its full pro rata share of the water right during this period. Thus, the Supreme Court affirmed the water court’s denial of the County’s application to change the water right.

This case serves as a warning to anyone who would seek to change water rights with complicated historical use patterns to a new use. A detailed demonstration of actual historical beneficial use on specific land will be required, even if the available records are unclear. In order to protect other water users against injury due to a potential expansion of an existing water right, the court will err on the side of denying a change of use application, if it is not convinced that the new use will not be greater than the historical irrigation use. It is crucial that water right holders conduct a thorough and credible historical use analysis, and compile sufficient evidence to convince the court just how the water right had been used over time. Otherwise, applicants run the risk of expending very substantial resources and time in a change-of-use proceeding, and end up having their applications denied.

Welborn Sullivan Meck & Tooley’s water attorneys have significant experience successfully obtaining change of water right decrees for municipal, industrial, and other clients. If you are considering changing a water right to a new use, we would be happy to discuss your plans.

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Employer Alert: Upcoming Changes to Overtime Laws will Broaden the Scope of “White Collar” Employees Eligible for Overtime Pay

The U.S. Department of Labor just released final rules updating the overtime regulations of the Fair Labor Standards Act (FLSA) that will significantly broaden the scope of employees eligible for overtime pay when the rules go into effect December 1, 2016: DOL Announcement.

Employers that are governed by the FLSA are required to classify their employees as either "exempt" or "nonexempt" for purposes of overtime pay. Most employees are “nonexempt,” and therefore entitled to overtime pay for hours worked over 40 in a workweek. However, the duties and salaries of some employees can qualify the employee for one of the FLSA exemptions for overtime, which means that these “exempt” employees will not receive overtime pay for hours worked over 40 in a workweek. The new FLSA rules impact the qualifications for the FLSA’s “white collar” overtime exemptions for executives, administrators, professionals and highly compensated employees by raising the threshold salary requirements.

Currently, salaried workers falling into the executive, administrator, and professional exemptions must earn at least $23,660 annually (or $455 per week) to qualify for an exempt classification. The new rules nearly double this salary threshold to $47,476 annually (or $913 per week). In general, this means that employees classified as exempt under the current law who earn above $23,660 but below $47,476 will lose their exempt status as of December 1, 2016. The new rules also raise the salary threshold for the highly compensated employee exemption from $100,000 per year to $134,004 a year. The last time the DOL changed the salary threshold for these regulations was twelve years ago, in 2004.

Additionally, while there is no change to the duties test for the white collar exemptions, the new rule will allow employers to use nondiscretionary bonuses and incentive payments (including commissions) to satisfy up to 10% of the new salary levels. More detailed information about all of the changes the new rules will bring to the overtime compliance procedures can be found on the DOL website here.

What are an employer’s options for employees losing their current exempt status? Several. If the employee rarely, if ever, works more than 40 hours in a workweek, one option is to let the employee convert to non-exempt status given the lack of impact as a practical matter. Of course, such employees must still be treated as all other non-exempt employees as far as recording worked hours and receiving overtime pay for all overtime hours worked, even if unexpected. For those employees who regularly work in excess of 40 hours per workweek, employers can maintain the exempt status by raising the salary to meet the new threshold levels. Other options for employees who regularly work more than 40 hours in a workweek that will lose their exempt status include redistributing workloads to other employees, changing workweek schedules to reduce overtime and reducing base pay so that the total amount of regular and overtime wages will remain largely the same.

The upcoming rule changes provide a good opportunity for employers to revisit their exempt classifications in all respects, including the new threshold salary levels. For any additional information regarding overtime pay and exemption requirements, please contact Danielle Wiletsky at dwiletsky@wsmtlaw.com

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Colorado Severance Tax – New Case Allows Operators To Deduct The Cost Of Capital

A decision in late April, 2016, by the Colorado Supreme Court, allows deduction of the cost of capital for construction of gas processing and transportation facilities in calculating Colorado severance tax.

In BP America Production Company v. Colorado Department of Revenue, 2016 CO 23, 2016 WL 1639829, the Colorado Supreme Court reversed the decision of the Colorado Court of Appeals regarding whether the cost of capital may be deducted from revenue in valuing oil and gas resources for purposes of calculating state severance tax. The court found that the Colorado severance tax statute authorizes a deduction for any transportation, manufacturing and processing costs, and that the cost of capital is a deductible cost that resulted from investment in transportation and processing facilities.

Colorado’s severance tax statute allows extractors to deduct from revenue “any transportation, manufacturing, and processing costs.” C.R.S. § 39-29-102(3)(a). The court emphasized the word “any” in this statute and said that when used as an adjective in a statute, the word “any” means “all.”

BP America Production Company’s (“BP’s”) predecessors had constructed facilities to process natural gas from coal seams and to transport it to market. The parties in the case had stipulated that if the cost of capital is allowed as a deduction, BP is entitled to refunds of $629,186 and $669,202 plus interest for tax years 2003 and 2004, respectively. The court stated that the cost of capital is the amount of money that an investor could have earned on a different investment of similar risk. In this case, the cost of capital is the amount of money that BP’s predecessors could have earned had they invested in other ventures rather than in building transportation and processing facilities. The court held that the cost of capital is a cost for purposes of the severance tax statute.

A memorandum dated May 6, 2016, from staff members to the Joint Budget Committee, states the Colorado Department of Revenue anticipates that the decision in this case will lead to significant refunds due to returns in process and that oil and gas producers will file amended returns as far back as allowed by the statute of limitations. The Department of Revenue estimates $98.4 million in required refunds. A bill that would address funding the refunds was passed by the General Assembly on May 11, 2016. (S.B. 16-218).

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2012 and 2013 Local Fracking Regulations Held Invalid and Preempted by State Law

In companion decisions issued May 2, 2016, the Colorado Supreme Court (Gabriel, J.) affirmed district court summary judgment orders invalidating home-rule oil and gas regulations concerned with hydraulic fracturing (“fracking”). The Court relied on the intent and scope of state-wide oil and gas legislation as reflected in the Colorado Oil and Gas Conservation Act, §§ 34-60-101 to -103, CRS (2015) (“the state Act”), and principles of operational preemption. The Court rejected express and implied preemption arguments.

In City of Longmont v. Colo. Oil and Gas Ass’n, Case No. 15SC667, the Court found Longmont’s voter-approved attempt to ban fracking to be in operational conflict with and, hence, preempted by the state Act. The Court noted that available alternatives to fracking did not lessen the state’s interest in fracking under the state’s Act and the district court’s factual finding that “virtually all oil and gas wells” in Colorado are fracked. The Court recognized that Longmont’s fracking ban implicated possible increased costs in producing oil and gas, reduced royalties, and the potential for a ripple-effect of local patchwork regulation across the state which could result in a de facto statewide ban notwithstanding the intent of the state Act. Similarly, in City of Fort Collins v. Colo. Oil and Gas Ass’n, Case No. 15SC668, the Court agreed that a 5-year voter-approved moratorium on fracking and storing fracking waste within the City was preempted by the state Act. The Court found the 5-year moratorium improperly rendered the state’s statutory and regulatory scheme superfluous, “at least for a lengthy period of time, because it prevents operators who abide by the Commission’s rules and regulations from fracking until 2018.” The Court, however, stated that it’s opinion expressed “no view as to the propriety of a moratorium of materially shorter duration.”

Hence, the Court invalidated Longmont’s ban and Fort Collins’s moratorium because they (i) involved questions of mixed state and local concern and (ii) each local regulation was preempted due to operational conflicts with the operation of the state Act. The Court also took the opportunity to reject a “beyond a reasonable doubt” standard of proof for the preemption proponent; rejected intervenor-citizens’ “inalienable rights” argument; and, clarified earlier Court preemption decisions (Voss and Bowen-Edwards), emphasizing (i) that the judicial question of “whether a matter is one of statewide, local or mixed state and local concern is separate and distinct from the question of whether a conflict between state and local law exists,” and (ii) that the preemption analysis requires the court to examine the interplay between state and regulatory schemes and to conduct “a facial evaluation of the respective regulatory schemes, not a factual inquiry as to the effect of those schemes ‘on the ground.’”

Once these Court decisions become final they are not subject to further review. Although these decisions may impact similar local government measures imposing local control over oil and gas activity in Colorado, they are not likely to stop or slow citizen-initiative efforts to increase local control of oil and gas activity.

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More Oil and Gas Regulation Headed for Colorado Ballots?

Come November, Colorado voters may decide whether oil and gas development should be subjected to more stringent regulation. Three ballot initiatives proposed by Boulder-based Coloradans Resisting Extreme Energy Development have survived legal challenges and are now headed for signature collection. Supporters have until August 8 to collect the necessary signatures to get these measures on the November ballot. Opponents, like Protecting Colorado’s Environment, Economy, and Energy Independence (PCEEEI), argue that passage of any of these measures could cripple Colorado’s oil and gas industry.

Proposed Initiative 63 (Right to Healthy Environment) creates a fundamental “right to a healthy environment” under the Colorado Constitution. It also specifies that local regulations that are more protective of a “healthy environment” will not be preempted by state law. Finally, the proposal creates a private right of action allowing any “aggrieved” party to sue for injunctive or declaratory relief, as well as punitive damages in some instances.

See text of the proposal here:
http://www.sos.state.co.us/pubs/elections/Initiatives/titleBoard/filings/2015-2016/63Final.pdf

Proposed Initiative 75 (Local Government Control of Oil and Gas Development) declares that “[o]il and gas development, including the use of hydraulic fracturing, has detrimental impacts on public health, safety, general welfare, and the environment.” It transfers the regulatory authority over oil and gas operations from the state to local governments, and specifically recognizes local authority to ban oil and gas development entirely.

See text of the proposal here:
http://www.sos.state.co.us/pubs/elections/Initiatives/titleBoard/filings/2015-2016/75Final.pdf

Proposed Initiative 78 (Mandatory Setback from Oil and Gas Development) increases minimum setbacks for new facilities (or for re-entry to a previously plugged and abandoned well) to 2,500 feet from schools, homes, hospitals, and “areas of special concern.” Current regulations require 500 foot setbacks from homes and 1,000 foot setbacks from “high occupancy buildings,” such as schools and hospitals. The proposal also authorizes local governments to require even greater setbacks.

PCEEEI estimates that this measure could eliminate “at least 87 percent of all new production in Weld County alone.” Governor Hickenlooper also weighed in on the matter, stating that the increased setbacks “would in many cases, invalidate people’s opportunity to extract natural resources that they own.”

See text of the proposal here:
http://www.sos.state.co.us/pubs/elections/Initiatives/titleBoard/filings/2015-2016/78Final.pdf

For more on the citizen initiative process, see:
http://www.wsmtlaw.com/cms-assets/documents/191009-726917.gpsolo-article-novdec-2014.pdf

Does any of this sound familiar? In 2014, two oil and gas related initiatives – one requiring 2,000 foot setbacks and one authorizing increased local regulation of oil and gas development –garnered the requisite signatures and headed for the ballots. At the eleventh hour Governor Hickenlooper and Democratic Rep. Polis announced a compromise which kept these (and two industry-backed initiatives) off the ballots in exchange for the creation of a task force charged with addressing citizens’ concerns about hydraulic fracturing. If Initiatives 63, 75, and 78 move forward, we may be headed for a repeat of this drama in the fall.

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2246 Hits

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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1281 Hits