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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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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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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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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Still Time for Business Tax Planning

As 2015 draws to a close, there is still time to reduce your 2015 tax bill and plan ahead for 2016. This memo highlights several potential tax-saving opportunities for business owners to consider.

• Defer Income into 2016. Deferring income to the next taxable year is sometimes a useful year-end planning tool. If you expect your taxable income to be higher in 2015 than in 2016, or if you anticipate being in the same or a higher tax bracket in 2015 than in 2016, you may benefit by deferring income into 2016. Of course, in the case of an individual taxpayer, exposure to the alternative minimum tax could reverse the standard planning. Some ways to defer income include:

o Use of Cash Method of Accounting: By adopting the cash method of accounting rather than the accrual method, you can put yourself in a better position to accelerate deductions and defer income. Because an automatic change to the cash method can be made by the due date of the return, including any filing extensions, there is still time to implement this planning idea. The following three types of businesses can make an automatic change to the cash method:
      small businesses with average annual gross receipts of $1 million or less (including those with inventories that are a material income producing factor);
      C corporations with average annual gross receipts of $5 million or less in which inventories are not a material income producing factor; and
      taxpayers with average annual gross receipts of $10 million or less.

Provided inventories are not a material income producing factor, sole proprietors, limited liability companies (LLCs), partnerships, and S corporations can change to the cash method of accounting without regard to their average annual gross receipts.

If you are already on the cash method or if you qualify for a change and elect to change to the cash method, delay year-end billing to clients so that payments are not received until 2016.

o Installment Sales: Generally, a sale occurs when you transfer property. If a gain will be realized on the sale, the installment method permits income recognition to normally be deferred until payments are received. Consequently, if you sell property prior to the end of 2015 and will receive one or more payments in future years, you should consider reporting the gain on the property using the installment method to defer payments (and tax) until next year or later.

o Interest and Dividends: Interest income earned on Treasury securities and bank certificates of deposit with maturities of one year or less is not includible in income until received. To defer interest income, consider buying short-term bonds or certificates that will not mature until next year. Unless you have constructive receipt of dividends before year-end, they will not be taxed to you in 2015.

• Accelerating Income into 2015. You may benefit from accelerating income into 2015. For example, if you anticipate being in a higher tax bracket in 2016, or perhaps you need additional income in 2015 to take advantage of an offsetting deduction or credit that will not be available to you in future tax years. However, accelerating income into 2015 could be disadvantageous if you expect to be in the same or lower tax bracket for 2016.

If you report your business income and expenses on a cash basis, send bills and pursue collection before the end of 2015. Inquire as to whether some of your clients or customers are willing to pay for January 2016 goods or services in advance. Any income received using these steps will shift income from 2016 to 2015.

o Qualifying Dividends: Qualified dividends are subject to rates similar to the capital gains rates. That is, for taxpayers below the 39.6% tax bracket, qualified dividend income is subject to a 15% rate. For taxpayers in the 39.6% bracket, the rate is 20%. However, qualified dividends may be subject to an additional 3.8% net investment income tax as well. Qualified dividends are typically dividends from domestic and certain foreign corporations. If you are not in the highest bracket for 2015, but you expect to be in 2016, consideration should be made as to authorizing any dividend payment prior to the end of 2015 to utilize the 15% favorable tax rate vs. the 20% rate at higher income levels.

• Business Deductions.

o Self-Employed Health Insurance Premiums: Self-employed individuals are allowed to claim 100% of the amount paid during the taxable year for insurance that constitutes medical care for themselves, their spouses, and their dependents as an above-the-line deduction, without regard to the general 10%-of-adjusted gross income floor. Self Employed Health Insurance includes eligible long term health care premiums.

o Equipment Purchases: If you purchase equipment, you may make a “Section 179 election,” which allows you to expense otherwise depreciable business property. For 2015, you may elect to expense up to $25,000 of equipment costs (with a phase-out for purchases in excess of $200,000) if the asset was placed in service during 2015.

Even though the Section 179 expense amount and phase-out have been much higher in the past, if Congress acts soon it could raise the 2015 Section 179 amounts. As of this writing, however, the recently enacted Bipartisan Budget Act of 2015 did not include any increase which makes it less likely that such legislation will be passed and if so whether that legislation would have retroactive application.

Even if expensing equipment purchases is not available under Section 179, careful timing of equipment purchases can result in favorable depreciation deductions in 2015. Generally, under the “half-year convention,” one may deduct six months' worth of depreciation for equipment that is placed in service on or before the last day of the tax year (if more than 40% of the cost of all personal property placed in service occurs during the last quarter of the year, however, a “mid-quarter convention” applies, which lowers your depreciation deduction.)

o Home Office Deduction: Expenses attributable to using the home office as a business office are deductible if the home office is used regularly and exclusively: (i) as a taxpayer's principal place of business for any trade or business; (ii) as a place where patients, clients, or customers regularly meet or deal with the taxpayer in the normal course of business; or (iii) in the case of a separate structure not attached to the residence, in connection with a trade or business. If you have been using part of your home as a business office, you should consider the amount of any deduction you should take because an IRS safe harbor could be used to minimize audit risk.

o NOL Carryback Period: If your business suffers net operating losses for 2015, you generally apply those losses against taxable income going back two tax years. For example, the loss could be used to reduce taxable income (i.e., generate tax refunds) for tax years as far back as 2013. Certain “eligible losses” can be carried back three years; farming losses can be carried back five years.

o Bad Debts: If you use the accrual method, you can accelerate deductions into 2015 by looking at the business’ accounts receivable and writing off those receivables that are totally or partially worthless. By identifying specific bad debts, you should be entitled to a deduction. You may be able to complete this process after year-end if the write-off is reflected in the 2015 year-end financial statements. For non-business bad debts (such as uncollectible loans), the debts must be wholly worthless to be deductible, and will probably only be deductible as a capital loss.

• Planning for 2015 Tax Increases and Potential Expiration of Tax Relief Provisions.

o Built-In Gains Tax for S Corporations (that previously were C corporations: An S corporation generally is not subject to tax; instead, it passes through its income or loss items to its shareholders, who are taxed on their pro-rata shares of the S corporation's income. However, if a business that was formed as a C corporation elects to become an S corporation, the S corporation is taxed at the highest corporate rate on all unrealized gains that were built in at the time of the election if the gains are recognized during a special look back period which is generally 10 years. In recent years, this special period was significantly shorter (most recently, it was five years). However, it is uncertain whether legislation will be passed to shorten the special holding period for 2015 or subsequent years and, if passed, whether that legislation would have retroactive application.

o Basis Adjustment to Stock of S Corporations Making Charitable Contributions of Property: The rule that the basis of an S corporation shareholder's stock is decreased by charitable contributions of property by the S corporation in an amount equal to the shareholder's pro rata share of the adjusted basis of the contributed property expired for contributions made in taxable years beginning after December 31, 2014. As a result, absent congressional action retroactively extending the prior rule for charitable contributions made in 2015, your stock basis will be reduced by your pro rata share of the S corporation's charitable contributions (at fair market value rather than adjusted basis). For example, if your S corporation contributed property with a $200 adjusted basis and $500 fair market value to a charity, your stock basis will be reduced by $500 instead of $200 unless Congress enacts legislation extending the prior rule.

o Exclusion of Gain Attributable to Certain Small Business Stock: Stock acquisitions that qualify as “small business stock” under § 1202 are subject to special exclusion rules upon their sale as long as a five-year holding period is satisfied. For qualified small business stock sold in 2015, the five-year look-back period is to 2010. A 50% exclusion applies for qualified small business stock acquired before February 18, 2009, and after December 31, 2014. A 75% exclusion applies for qualified small business stock acquired after February 17, 2009, and before September 28, 2010. A 100% exclusion applies for qualified small business stock acquired after September 27, 2010, and on or before December 31, 2014. For qualified small business stock acquired in 2015, only 50% of the gain is excluded from gross income (after the five-year holding period is met). Unless Congress acts before the end of 2015 to reinstate the 100% exclusion for stock acquired in 2015 (and held for at least five years), gain on the sale of such stock acquired in 2015 may be subject to the 50% exclusion rate.

The foregoing is general in nature and may or may not apply to your circumstances. Because every business is unique, you should review your situation with your tax advisers prior to implementing any strategy or making decisions concerning taxes as the year-end approaches.

If you have any questions, please do not hesitate to call.

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Get out of my sandbox! Expulsion of a LLC Member under Wyo. Stat. 17-29-602

So, you have a bad apple as a member of your Wyoming limited liability company (LLC), how do you get rid of them? The best option is usually to reach an agreement for the company or a specific member to purchase the troublemaker’s membership interest. If, however, an amicable solution cannot be reached, the company may be able to expel the member pursuant to Wyo. Stat. 17-29-602. Section 602 governs the general circumstances when dissociation of a member occurs but also provides for expulsion of a member in the following circumstances: i) pursuant to the company’s operating agreement; ii) with unanimous consent of the other members; and iii) by judicial action.

Pursuant to Section 602, the easiest course of action is to expel the member under the company’s operating agreement but, unfortunately, few operating agreements address the expulsion of troublemakers. The next simplest course of action under Section 602 is to vote them out. However, this option is only available in very limited circumstances. Specifically, voting the bad apple out pursuant to the statute is available when it is either: unlawful to carry on the company’s activities as long as the troublemaker remains a member or there has been a transfer of all of the troublemaker’s transferable membership interest. Note: even if the troublemaker’s membership interest has been fully transferred, they cannot be expelled if the transfer was: a transfer for security purposes or due to a charging order in effect under Wyo. Stat. 17-29-503.

The company may be left with the most expensive and least desirable but still possible remedy of filing a lawsuit to expel the member. In order to expel the troublemaker by judicial action, the company (as opposed to an individual member) must bring the action and prove one of the following:

(A) the member has engaged, or is engaging, in wrongful conduct that has adversely and materially affected, or will adversely and materially affect, the company’s activities;

(B) the member has willfully or persistently committed, or is willfully and persistently committing, a material breach of the operating agreement or the person’s fiduciary duties or obligations under Wyo. Stat. 17-29-409; or

(C) the member has engaged in, or is engaging in, conduct relating to the company’s activities which makes it not reasonably practicable to carry on the activities with the person as a member.

Beyond the expense and general litigation risk for the company, even if the member is judicially expelled, there are a couple of caveats that require careful consideration. First and foremost, expulsion of the troublemaker will successfully remove him from all management and other business operations BUT the troublemaker will continue to own his interest in the company as a “transferee interest” also known as an “economic interest”. See Wyo. Stat. 17-29-603. Accordingly, the former member will be entitled to certain financial information owned by the company and, perhaps more importantly, will continue to be entitled to his share of the profits, losses and distributions under the company’s operating agreement. So, effectively, the company may kick the offending member out of the sandbox but still have to pass him buckets of sand to build his castle. Secondly, if the company is member-managed, the troublemaker’s fiduciary duties as a member end with regard to matters arising and events occurring after his dissociation. Terminating fiduciary duties owed by the troublemaker may be too disadvantageous to the company for the company to expel him, particularly if the member begins competing with the company while still receiving distributions as an economic interest owner.

Expulsion of a member is, obviously, an aggressive course of action and must be thoroughly examined. The risk of litigation to the company and its other members must be studied even if expulsion occurs under the operating agreement or by unanimous vote. However, Section 602 does provide some options for a company to remove a problem member at least from the company’s management and business operations.

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Secretary of Agriculture Recommends Cancellation of Montana Oil and Gas Leases

On October 30, 2015, Secretary of Agriculture Tom Vilsack sent a letter to Secretary of the Interior Sally Jewell recommending that BLM cancel 18 long-held oil and gas leases located on Forest Service managed surface in an area of Northwestern Montana called the Badger-Two Medicine. These leases, originally issued in 1982, have been the focus of controversy for many years, largely based on their proximity to areas of cultural significance to the Blackfeet Tribe and Glacier National Park. The leases have been suspended by BLM for almost twenty years, but recent judicial decisions are forcing BLM to make a decision on the ultimate fate of the leases in the coming months.

In his Letter, which follows and relies on the earlier findings of the Advisory Council on Historic Preservation (see link to 9/23/15 blog below) Secretary Vilsack argues that permitting oil and gas development in the area would have “adverse effects” that cannot be mitigated through site-specific requirements. Secretary Vilsack pointed out that in the time since the leases were issued, “there have been many policy developments, not only with regard to historic properties of traditional religious and cultural significance to Indian tribes, but also in Federal-tribal relations. . . . The [Forest Service] has worked diligently to comply with new requirements by pursuing oral histories and contracting supporting archeological and ethnographic work, which gradually revealed the unique and special nature of the Badger-Two Medicine.” With the information gained over the last 30 years, Secretary Vilsack concludes that the leases should not have been issued in the first place and should therefore be canceled by BLM.

Although BLM has ultimate decision-making authority under the Mineral Leasing Act of 1920 on lease cancellation, Secretary Vilsack’s letter, on behalf of the Surface Managing Agency, is likely to carry significant weight. Under an order from U.S. District Judge Richard Leon, BLM has until November 23 to either lift the suspensions or cancel the leases. If BLM cancels the leases, it is likely to face further legal challenges from the lessees.

Advisory Council on Historic Preservation Recommends Cancellation of Oil and Gas Leases in Montana

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Finally – A Policy to Streamline the BLM Communization Agreement Process – IM 2015-124

Dated and effective July 17, 2015, the Bureau of Land Management (“BLM”) issued Instruction Memorandum 2015-124 (“IM-2015-124”). This BLM guidance significantly changes the way federal Communization Agreements (“CAs”) are administered and, for the most part, eliminates some of the cumbersome issues for operators applying for CAs. CAs are used to combine isolated or small federal mineral and/or tribal parcels with fee minerals to form a spacing or proration unit that complies with state law and allows for development of tracts that could not be independently developed or operated on their own.

In addition to attempting to “clean-up” the CA Process, IM-2015-124 addresses some questionable jurisdictional issues. Before IM-2015-124 was issued, there were concerns by industry that the BLM was attempting to expand its management beyond its authorized jurisdiction over federal minerals to fee minerals. For example, in some instances, the language in approved CAs appeared to require the operator to account to the BLM not only for federal minerals but for all minerals, including fee. However, IM-2015-124 now limits the CA responsibilities of the BLM to federal minerals and the Bureau of Indian Affairs to tribal minerals. We note that many of the jurisdictional issues the IM attempts to clarify were called into question by the BLM’s recently proposed rule modifying Onshore Oil and Gas Order No. 3. For more information on these inconsistencies, see Western Energy Alliance’s comment letter on the proposed changes to Onshore Order No. 3:

http://cdn.westernenergyalliance.org/sites/default/files/FINAL%2010.9.15%20OO3%20comment%20letter.IPAA_.WEA_.pdf

In any event, until the changes proposed in Onshore Order No. 3 are made final, the components of IM-2015-124 will govern. Some of the notable changes to the CA process in IM-2015-124 include:

1. An operator may self-certify that the necessary signatures have been obtained (working interest owners and record title owners in the Federal and Indian leases). Rather than submit all of the necessary signatures, an operator can submit the certification statement, word for word from IM-2015-124, to the BLM with its CA, and the BLM will rely on that statement;

2. CA: Exhibit A – the operator may identify all non-Federal/non-Indian interests as a single tract;

3. CA: Exhibit B – An operator may aggregate all of the non-Federal/non-Indian interests into a single entry entitled “Other Interests,” with total aggregate acreages; and

4. CA: Exhibit B – Due to the revisions to non-Federal/non-Indian interests in Exhibits A and B, an operator does not need to provide the lease information for those interests.

The BLM’s goal is to have all CAs in place prior to the date of first production. In fact, the BLM has required applicants appearing before the Colorado Oil and Gas Conservation (“COGCC”) to include specific language in spacing orders that addresses CAs and timing for the operator to apply and comply with the CA process. The COGCC order language usually requires an operator to submit a CA concurrent with the filing of an APD or at least 90 days before the anticipated date of first production.

Any operators actively submitting CAs to the BLM should be well-versed in the changes addressed in IM-2015-124 affecting BLM Manual 3160-9 and be prepared to submit a CA prior to production of a well affecting Federal or Indian interests.

IM-2015-124 can be found at:  http://www.blm.gov/wo/st/en/info/regulations/Instruction_Memos_and_Bulletins/national_instruction/2015/IM_2015-124.html

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