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Fracking News & Flashes

Our Commentary on Recent Fracking News

  • EPA Methane Regulations for Oil and Gas Industry Finally Finalized and Immediately Headed Back to Court
    September 16, 2020

    As discussed in this previous post, EPA recently released two rules changing the volatile organic compound (“VOC”) and methane emissions requirements for new sources in the oil and gas sector, which alter or roll back some of the requirements put in place under the Obama administration (“Methane Rule”). The predecessor to EPA’s most recent methane regulations spent significant time bouncing back and forth between the agency and several federal courts in Washington D.C.

    On September 14, 2014, EPA’s Methane Rule was officially published in the federal register, meaning that the roll-back has now become effective. On the very same day, a group of states filed a new law suit in the federal D.C. Circuit court asking the court to review EPA’s new methane regulations. Industry members, trade groups, and environmental organizations will have 30 days to ask to ask the court to join in the law suit.

    Brief History of EPA’s Methane Regulations for the Oil and Gas Industry

    On June 3, 2016, EPA finalized Quad Oa — more formally known as the “New Source Performance Standards (NSPS) for VOC and methane emissions from the oil and gas sector.” This was the first time EPA regulated methane from the oil and gas sector, and the rule applied to upstream, midstream, and downstream operations. Before then, EPA had only regulated VOCs from the sector, and since VOCs and methane both come from natural gas leaks, the previous regulations (“Quad O”) had the effect of also limiting methane emissions.

    Methane was regulated as an air pollutant based on its contribution to climate change. As EPA has previously explained, the oil and gas industry is a “significant source of emissions of methane, a potent greenhouse gas with a global warming potential more than 25 times that of carbon dioxide.” EPA estimates that the oil and natural gas production, natural gas processing, and natural gas transmission and storage sectors emit 25% of U.S. anthropogenic methane.

    By explicitly regulating methane as a separate air pollutant, Quad Oa acted as a stepping stone to additional methane regulations in the future. While Quad Oa only applied to new or modified sources after the rule’s effective date, releasing the rule triggered an obligation to regulate methane from existing wells and equipment. In November 2016, EPA followed up on that intention by sending an Information Collection Request to operators, asking them to identify ways to control methane from existing oil and gas sources. In March 2017, the Trump administration’s EPA canceled the Information Collection Request, and in April, EPA announced its intention to review Quad Oa. As a result, existing sources of methane emissions in the oil and gas industry are not currently regulated by EPA.

    Why Does This Roll-Back Matter? Existing Sources and Future Methane Regulation

    On the surface, EPA’s Methane Rule removes some of the regulatory requirements that industry considered burdensome, including leak monitoring and repair and recordkeeping and reporting requirements. Among the biggest changes was removing transportation and storage sectors (including midstream or pipeline companies) of the oil and gas industry from VOC and methane regulation entirely. As EPA explained, the “Clean Air Act requires EPA to make a formal finding that a pollutant contributes significantly to air pollution before setting NSPS requirements. Since the Obama EPA did not make this finding, the addition of the transmission and storage segment to the oil and gas category and the additional methane control requirements in the 2016 rule were inconsistent with the law.”

  • Texas Railroad Commission Publishes Proposed Order on Proration Volume for Oil Wells
    April 30, 2020

    On April 29, 2020, the Texas Railroad Commission (the “Commission”) published a proposed order that it plans to consider at its May 5 Commissioner’s Conference.  The proposed order was brought forth by Commissioner Ryan Sitton, following weeks in which the Commission entertained arguments for and against such proration measures. The Commission will accept public comments on the proposed order before Monday, May 4, 2020.

    The proposed order would limit Texas producers to a “Proration Volume” of 80% daily production multiplied by the number of days in a month, based on an operator’s highest average daily oil volume for the month-long periods of October, November, or December of 2019.  The 80% limit is based on an initial “Market Demand Factor,” which is subject to future review by the Commission. Penalty for non-compliance will be $1,000.00 for each barrel of oil produced in excess of the allowable volume, on a monthly basis.

    Notably, under the proposed order, the proration measures would not take effect until other oil-producing states and countries (such as OPEC+) agree to certain “Complementary Proration Measures” totaling at least 4 million barrels of crude oil a day (in addition to those production cuts already announced by OPEC+). The proration measures would last until the earlier of when such “Complementary Proration Measures” ceased, or when global market demand for crude oil exceeds 85 million barrels a day. By linking proration to similar measures taken by other states and countries, the proposed order seeks to address previously voiced concerns that Texas producers should not alone shoulder the burden of production cuts.1 The proposed order also contains some exceptions and potential relief mechanisms:

    • The proposed order contains a definition of an “Excluded Operator,” which is one that produced less than 1,000 barrels of oil per day;
    • The Commission may reduce or eliminate a non-compliance penalty upon a showing of “good faith,” though the proposed order does not provide a definition or example of “good faith;”
    • Any operator may request a hearing to determine if the proposed order shall not apply to individual wells or leases, though the proposed order gives no guidance on what circumstances may qualify for the exception.

    Significant uncertainty exists as to whether this proposed order, in its current form, would be approved by the three-member Commission next week. For example, Chairman Wayne Christian has already expressed skepticism as to the need for such proration measures.

    Texas has not implemented oil proration since 1931, so there exists limited precedent for both Commission enforcement or court challenges, should the order pass. Vinson & Elkins energy and regulatory attorneys have extensive experience advising clients on these regulatory issues and their potential impacts, as well as representing clients before the Commission.

    1 The Oklahoma Corporation Commission plans to similarly consider proposed proration measures next month. 

  • District Court Upholds BLM Rollback of 2015 Hydraulic Fracturing Rule
    April 2, 2020

    On March 27, 2020, the U.S. District Court for the Northern District of California granted the Bureau of Land Management’s (“BLM”) motion for summary judgement, upholding the agency’s decision to rescind, or roll-back, hydraulic fracturing regulations finalized during the Obama Administration (the “2015 Rule”). The Court’s decision in State of California v. Bureau of Land Management means that oil and gas operators on Federal and Indian lands will not have to comply with the additional requirements in the 2015 Rule. Instead, operators must continue to follow existing state and federal requirements. Because the 2015 Rule never went into effect before it was rescinded, operators will not have to change any of their existing practices.
    After studying the existing regulatory requirements, the Obama Administration decided that additional federal regulations were needed for hydraulic fracturing on Federal and Indian land. BLM passed the 2015 Rule, which would have included a comprehensive set of well-bore integrity requirements, the use of tanks for the interim storage of recovered waste fluids, mandatory notifications and waiting periods for key parts of the fracturing process, and chemical disclosures.

    In 2017, BLM rescinded the 2015 Rule because it believed it was “unnecessarily duplicative or state and some tribal regulations and imposes burdensome reporting requirements and other unjustified costs on the oil and gas industry.” The State of California and several environmental groups challenged BLM’s rescission of the 2015 Rule in a federal district court in California under the Administrative Procedure Act (“APA”), National Environmental Policy Act (“NEPA”) and Endangered Species Act (“ESA”). Essentially, these groups argued that BLM did not follow the proper procedures, complete the necessary level of environmental analysis, or sufficiently explain its reason for rescinding the 2015 Rule.

    In challenging the Rescission under the APA, California argued that the change in policy was an abuse of discretion because the agency failed to offer a reasoned explanation for reversing its policy and that its proffered reasons for the reversal run counter to the evidence before the agency. The Court disagreed and held that while the BLM could have provided more detail, its explanation was sufficient and “did enough to clear the low bar of arbitrary and capricious review, and that is all the law requires.” The Court also held that NEPA and the ESA did not apply to the Rescission, reasoning that there was no impact to the environment or endangered species because the 2015 Rule never went into effect and there was never change to the environmental status quo.

    The Rescission will save oil and gas operators from complying with additional federal requirements. But V&E Environmental & Natural Resources Counsel Corinne Snow, who argued this case on BLM’s behalf during her tenure at the U.S. Department of Justice, notes that as a practical matter, the 2015 Rule requirements are now largely duplicative of regulations now in place many states where hydraulic fracturing occurs on BLM lands, and BLM requires operators to also comply with the laws of the state where Federal or Indian land is located.

    Read our full analysis of State of California v. BLM here.

  • Pennsylvania Supreme Court finds that Rule of Capture May Bar Trespassing Claims
    February 12, 2020

    On January 22, 2020, the Pennsylvania Supreme Court announced its decision in Briggs, et al. v. Southwestern Energy Production Company, No. 63 MAP 2018 (Penn. Jan. 22, 2020), vacating a Superior Court opinion and holding that the rule of capture applies to fracking and protects fracking companies from trespass liability when a well taps into oil and gas below a neighboring property so long as there is no actual physical invasion. The rule of capture is a common law principle stating that the first person to “capture” a resource owns that resource, regardless of whether it is drained from below adjacent land. With this decision, Pennsylvania joins Texas as one of two states with cases holding that fracking, in and of itself, does not constitute trespass. In limiting its holding to situations where there is no physical invasion, the Supreme Court leaves an opening for landowners who can prove actual physical invasion, difficult though that may be.

    In Briggs, the Briggs Family sued Southwestern Energy, an energy company conducting fracking operations on neighboring land. Southwestern Energy did not have leasehold interests on the Briggs Family’s land. The Briggs Family sued for trespass and conversion, alleging that Southwestern Energy’s wells illegally drained natural gas from beneath their land. Southwestern Energy argued that it did not physically invade the Briggs Family’s property and, to the extent it produced any gas drained from that property to its lease, it was protected by the rule of capture. In response, the Briggs Family argued that the rule of capture should not apply in circumstances where gas has been captured by fracking, because (1) “artificially stimulating” the cross-boundary flow of oil and gas renders the rule of capture inapplicable and (2) “any time natural gas migrates across the property lines resulting, directly or indirectly, from hydraulic fracturing, a physical intrusion into the plaintiff’s property must necessarily have taken place.”

    In its opinion, the Supreme Court rejected the Briggs Family’s arguments. The Supreme Court noted that the characterization of fracking as “artificial stimulation” was a distinction without a difference—all drilling is artificial. Even more to the point, the Supreme Court stated that early decisions had upheld application of the rule of capture to well-shooting and other forms of well stimulation. The Supreme Court held that the rule of capture protects fracking companies from trespass liability when a well taps into oil and gas below a neighboring property unless there is a physical invasion. Since the Briggs Family had not actually alleged physical intrusion into their subsurface property and the record did not support the conclusion that physical intrusion had occurred, the Supreme Court remanded the case for further factual development. Had the Briggs Family alleged actual invasion by fracture, fluid, or proppant, the Supreme Court indicated that a claim for trespass would have been viable, at least at the pleading stage.

    Briggs has been viewed as a split decision by landowners and fracking companies. Although it upholds the rule of capture’s applicability to fracking, it does not fully foreclose liability for drainage resulting from fracking. Ultimately, the Supreme Court’s ruling places the burden on landowners to prove that a physical intrusion onto their property actually took place—a pricey and complicated proposition.

  • Democratic Lawmakers Introduce Bill to Ban Fracking Nationwide
    January 28, 2020

    On January 28, 2020, presidential candidate Senator Bernie Sanders (D-VT) and Senator Jeff Merkley (D-OR) introduced Senate Bill 3247, which, if enacted as proposed, would ban hydraulic fracturing nationwide by 2025. The Bill, known as the “Ban Fracking Act” is Congress’ first-ever proposal to ban fracking across the United States and would achieve a total ban in three phases.

    First, the Bill would institute an immediate ban on all new federal permits for fracking-related infrastructure. This includes pipelines, natural gas import and export terminals, natural gas storage, ethane cracker plants, natural gas power generation plants, among other fracking infrastructure. The Bill also calls for an immediate national survey of all oil and natural gas wells in the United States where fracking has been or is being used. The survey will gather data on well location, proximity to homes and schools, production rates, and health and safety violations.

    Second, using data gathered in the national survey, the Bill would revoke federal permits for fracking within 2,500 feet of homes and schools in 2021. Finally, the Bill would ban all fracking in the United States, both offshore and onshore, in 2025.

    The Bill directs the Department of Labor to partner with other federal agencies and stakeholders to develop recommendations for ensuring the “health and safety of individuals residing in, and the prosperity of natural gas- and oil-producing regions” during the fracking phaseout. However, the Bill does not authorize any federal funds to implement any recommendations that the Department of Labor and other federal agencies may develop.

    The Bill has been referred to the Senate Energy and Natural Resources committee but will face an uphill battle in the currently Republican-controlled Senate. The Bill has several ambiguities and gaps. For example, the Bill does not specify what “federal permits for fracking” will be revoked in 2021 nor does it address any takings issues that would likely arise from banning fracking on private property. If adopted as written, the Bill will likely suffer setbacks due to legal challenges.

    Although unlikely to become law this year, the Bill may be a sign of how a progressive Democratic administration may approach energy policy as Democratic presidential candidates Senator Bernie Sanders and Senator Elizabeth Warren have both pledged to ban fracking.

    Read the full text of Senate Bill 3247 here.

  • California Announces “Independent Reviews” for New Hydraulic Fracturing Permits, Audit of Current Permit Approval Process
    November 20, 2019

    On November 19, 2019, the California Department of Conservation’s Division of Oil, Gas and Geothermal Resources (“DOGGR”) announced that all new permits for well stimulation operations such as hydraulic fracturing must be reviewed by third-party, independent scientists “to ensure the state’s technical standards for public health, safety and environmental protection are met prior to approval of each permit.”  These reviews will be conducted by experts at the Lawrence Livermore National Laboratory in Livermore, California.

    The requirement for independent reviews is a temporary measure pending a broader overhaul of California’s well stimulation permitting regime, which arises out of recent legislation that revised the name and mission of DOGGR, which will be renamed the Geologic Energy Management Division, or “CalGEM,” effective January 1, 2020.  Similar to Colorado’s S.B. 19-181, California’s A.B. 1057, which was signed into law in October 2019, also specifically requires that CalGEM’s mission include “protecting public health and safety and environmental quality, including reduction and mitigation of greenhouse gas emissions associated with the development of hydrocarbon and geothermal resources in a manner that meets the energy needs of the state.”  DOGGR began a review of its process for approving well stimulation permits in July 2019, after it was reported that the issuance of such permits had doubled since Governor Newsome took office in January 2019.  More recently, DOGGR requested an independent audit of its permitting processes for well stimulation and underground injection control by the California Department of Finance’s Office of State Audits and Evaluations.

    In addition to this ongoing review of well stimulation permitting procedures, DOGGR announced a new rulemaking effort aimed at strengthening protections for public health and safety near oil and gas extraction facilities.  The rulemaking process will begin in 2020 with “a series of pre-rulemaking workshops with interested parties to seek input on the best ways to protect human health through new rules.”  A variety of environmental and public health authorities are expected to consult on the forthcoming rulemaking, including the California Department of Public Health and the California Environmental Protection Agency.  Finally, DOGGR also announced a moratorium on new extraction wells that use high-pressure cyclic steaming to break apart underground geological formations to extract oil, a process that has been linked to recent oil leaks in Kern County, California.

    It remains to be seen how the independent panel will implement its new authority to evaluate well stimulation permits pending California’s continuing review of its permitting processes.  To the extent that this review recommends regulatory changes to California’s permitting regime, such changes would require a future notice and comment rulemaking.  In the meantime, operators should prepare to engage in the forthcoming rulemaking effort relating to protections for public health and safety near oil and gas extraction facilities.  As Colorado’s failed Initiative 97/Proposition 112 demonstrated in 2018, measures as simple as increased setback distances can have devastating effects on the percentage of surface lands available for production.

    Read DOGGR’s announcement in full here.

  • Texas Publishes Proposed Safety for Rural Gathering Pipelines
    October 18, 2019

    The Railroad Commission has formally proposed rules that would add safety requirements for rural gathering pipelines. The action is far narrower than the draft rules that the Railroad Commission proposed this summer for informal comment. Historically, rural gathering pipelines have been largely unregulated. This summer’s draft proposal would have imposed on rural gathering lines broad proscriptive requirements related to corrosion control, damage prevention, public education, line marking, and leak surveys above and beyond rules recently finalized by the federal Pipeline and Hazardous Materials Safety Administration. The potential major change drew significant industry attention and many informal comments, both in writing and at a public meeting, including comments that the draft rules were not tied to identified public safety risks.

    At its October 1 meeting, the Commission formally proposed safety rules that are far narrower than the draft proposal this summer. Rather than the proscriptive requirements proposed in draft this summer, the current proposed rules would instead subject pipeline operators to a general performance standard – operate in a “reasonably prudent manner to promote safe operation” – and the following incident related requirements: 

    • Report incidents and accidents to the Commission (16 TAC 8.110(c));
    • Conduct investigations after incidents or accidents and cooperate with the Commission during a Commission investigation (16 TAC 8.110(d)); and
    • Submit, at the Commission’s request, corrective action plans to remediate accidents, incidents, threats to the public, or complaints (16 TAC 8.110(e)).

    The proposed rules align with H.B. 2982 (2013), which authorizes Commission rulemaking for rural gathering pipelines “based on the risks the transportation and facilities present to the public safety.” Indeed, the Commission acknowledged in the preamble to the proposed rules that it “has recognized the need to compile more accurate and complete information regarding the incidents and accidents that are occurring on gathering systems located in Class 1 locations and rural areas.” That said, the Commission also expressed its belief that these new reporting, investigation, and corrective action requirements “will allow the Commission to gather accurate data and analyze trends in incident or accident occurrences,” permitting it “to more thoroughly assess the risks [that rural gathering pipelines] . . . present to the public safety.” Thus, the data the Commission intends to gather could provide the Commission with the legal basis for a more expansive rule package in the future. 

    The proposed rules were formally published in the Texas Register on October 18, opening a 30-day public comment period.

  • California Legislature Looks to Colorado in Considering Increased Setbacks
    April 30, 2019

    On April 22, 2019, the California Assembly’s Natural Resources Committee passed Assembly Bill 345 (“AB 345”), which, similar to Colorado’s failed Proposition 112 ballot initiative, would require that all new oil and gas development and rework operations on non-federal land be located at least 2,500 feet from any residences, schools, childcare facilities, playgrounds, hospitals, and health clinics. These requirements would take effect beginning on January 1, 2020. In addition, the bill authorizes cities and counties to impose setback requirements even greater than the 2,500-foot base requirement.

    The bill includes a variance mechanism whereby operators could obtain a reduction to the “maximum achievable” setback distance where necessary to access legal subsurface rights. Applications for a variance must include “competent, substantial, and relevant evidence” demonstrating, among other things, that the proposed variance is “consistent with the intent” of AB 345 and “protect[s] public health and safety.” Such variance requests would be subject to review by the state’s Oil and Gas Supervisor. However, an analysis prepared by the Assembly’s Natural Resources Committee observed that “it is unlikely the variance could ever be used” because, counter to the requirement that a variance be “consistent with” AB 345, the bill explicitly declares that “[p]roximity to oil and gas extraction, including the use of hydraulic fracturing, well acidization, and other nonconventional oil and gas extraction techniques, adversely impacts public health and safety.”

    As was the case with Proposition 112 in Colorado, implementing the requirements of AB 345 could have a devastating impact on new oil and gas exploration and production activities in California, which currently ranks fourth among states in annual oil production. The Natural Resources Committee’s analysis states that even a lower 1,500-foot setback from only residential developments would have affected 65 permits issued in Los Angeles County alone in 2018. Even more troubling for California operators is the Committee’s observation that, as currently drafted, the “definition of new oil and gas development and rework operations may capture any permit necessary to keep existing wells producing.” The California Division of Oil, Gas, and Geothermal Resources issued 1,100 such permits last year, amounting to 15% of the total permits it issued. Similarly, the Committee found that AB 345’s definitions of “oil and gas development” and “rework operations” subject to the setback requirement could include routine repairs, the addition of new flowlines, or additional treatment of waste.

    The bill will now move to the Committee on Appropriations for further consideration. Should the bill advance out of committee, it would move to the Assembly for further readings and a vote. To become law, the bill must be passed by the Assembly and Senate, and then approved by the Governor, who can either sign the bill into law, or allow it to become law without signature. Read the current text of AB 345 in full here.

    Finally, AB 345 was not the only bill affecting the oil and gas industry to advance out of the Assembly’s Natural Resources Committee on April 22. The Committee also passed AB 1440, which would again borrow from Colorado by eliminating language encouraging the development of oil and gas resources from the statutory mandate of the California’s Oil and Gas Supervisor. Colorado, of course, recently enacted legislation that revised the mandate of the Colorado Oil and Gas Conservation Commission to focus primarily on the protection of public health and the environment, rather than “fostering” the development of oil and gas resources. Like AB 345, AB 1440 will now move to the Committee on Appropriations for further consideration. Read the current text of AB 1440 in full here.

  • Colorado House Passes S.B. 19-181, Sending the Amended Bill Back to the Senate
    April 1, 2019

    On March 29, 2019, the Colorado House of Representatives passed S.B. 19-181, the sweeping oil and gas reform legislation introduced by Senate Democrats on March 1. The final House vote to pass the legislation followed nearly six hours of floor debate, the adoption of almost a dozen amendments, and the rejection of several others. While the majority of the amendments adopted by the House are minor and clarifying in nature, several affected the substance of S.B. 19-181:  

    • New language requires local governments to regulate the surface impacts of oil and gas operations “in a reasonable manner.”
    • The House made significant changes to the provisions relating to the composition of the Colorado Oil and Gas Conservation Commission (“COGCC”). The amended bill now requires a seven-member, “professional” COGCC. This means that the five COGCC members appointed by the Governor (subject to the consent of the Colorado Senate) will be excluded from other employment and entitled to compensation. The remaining two COGCC members comprising the seven-person commission will consist of the directors of the state agencies for natural resources and public health and environment, who will serve as non-voting members.
    • New language clarifies that the reports issued by the technical review board, the COGCC-appointed body made available to review “issues in dispute” as between local governments and operators in the siting process, must not address the economic effects of local governments’ preliminary or final siting determinations.
    • The House lowered the percentage of owners necessary to force pooling from 50% to 45%.

    Despite these amendments, the key provisions of S.B. 19-181 remain in place. The bill will now return to the Senate for a floor vote to consider the amended legislation. That vote is currently scheduled for April 2, although additional delays remain possible. If the Senate votes to pass S.B. 19-181 as amended, the bill would move to Governor Polis’s desk for signature. Governor Polis has already expressed his support for the legislation. Read the current version of S.B. 19-181 as amended here.

  • Colorado S.B. 19-181 Passes Senate
    March 14, 2019

    The Colorado Senate voted along party lines on March 13, 2019, to pass S.B. 19-181, the sweeping oil and gas reform legislation introduced by Senate Democrats less than two weeks ago. The Senate vote was not without controversy. In an attempt to delay action on S.B. 19-181, Senator John Cooke requested on March 11th that a 2,000-page bill be read in its entirety on the Senate floor. Senate Democrats responded by using five computers to simultaneously read various portions of the bill out loud at speeds well beyond the capacity of human speech. Cooke, along with other Senate Republicans, brought suit against Democratic leadership on March 12th, arguing that the bill must be read intelligibly. Although a Denver judge has issued a temporary restraining order against Democratic leadership and further proceedings in that case are scheduled for March 19th, the fact remains that the Colorado Senate has passed S.B. 19-181, which will now move to the Colorado House of Representatives for further consideration.

    The precise timing for House action on S.B. 19-181 remains unknown; currently, the bill does not appear on the House calendar. Nonetheless, given how quickly the bill has moved thus far, and the composition of the Colorado House—41 Democrats to 24 Republicans—the bill could reach the Governor’s desk as early as the week of March 18th. Governor Polis has already expressed his support for the legislation.

    While additional amendments remain possible, oil and gas operators in Colorado should consider the version of S.B. 19-181 that passed the Senate likely to become law, and likely very quickly. The reengrossed version of the bill—including all amendments—passed by the Senate is available here. Notable amendments include:

    • requiring the Colorado Oil and Gas Conservation Commission (“COGCC”) to review its leak detection and repair rules to consider making them more stringent;
    • requiring the COGCC to promulgate rules (i) regulating wellbore integrity and (ii) requiring certification for certain oil and gas industry workers, including compliance officers responsible for OSHA and industry standard codes, those handling hazardous materials, and welders;
    • allowing local governments and operators to seek review of local governments’ location and siting decisions by a technical review board appointed by the COGCC Director to assess any “issues in dispute,” including whether (i) the local government’s siting determination “could affect oil and gas resource recovery,” (ii) the local government’s determination is “impracticable” or would require technologies that are “not available,” and (iii) the operator is proposing to use “best management practices”;
    • stating explicitly that local governments may regulate the land use and siting of oil and gas facilities in a manner “more protective or stricter” than the state-level requirements; and
    • requiring the COGCC Director to submit a report to the Colorado General Assembly by January 1, 2021, regarding “any recommended structural changes to the Commission.”

    The REMI Partnership, a “partnership of public and private organizations” that aims “to develop independent, fact-based analysis that quantifies the broader economic impacts associated with policy changes” in Colorado has estimated that if S.B. 19-181 cuts new oil and gas production in the state by 50%, Colorado would lose 120,000 jobs, more than $8 billion in state and local tax revenue, and over $58 billion in GDP by 2030. Read our updated analysis of S.B. 19-181 in its entirety here.

  • Colorado S.B. 19-181 Advancing Quickly As Hearings Continue
    March 8, 2019

    Colorado S.B. 19-181, the sweeping oil and gas reform legislation introduced last week in the Colorado General Assembly, is advancing quickly through the six committee hearings necessary to reach a floor vote. The bill has already been approved by the Senate Transportation and Energy Committee and the Senate Finance Committee after votes along party lines. The Senate Transportation and Energy Committee’s hearing on March 5th demonstrated the controversial nature of S.B. 19-181, drawing almost 200 people to testify over the course of a twelve-hour hearing. Thus far, the amendments made to the bill have been largely clarifying in nature, although additional amendments remain possible should the legislation continue to advance.

    S.B. 19-181 is set for hearing by the Senate Appropriations Committee on March 8th. Given the pace at which this bill is currently moving, it remains imperative that all oil and gas operators in Colorado familiarize themselves with this legislation as soon as possible and monitor its continued progress through the General Assembly. Read our analysis of S.B. 19-181 here. The full text of the proposed legislation as introduced is available here.

  • Colorado S.B. 19-181 Proposes Sweeping Oil & Gas Reforms
    March 6, 2019

    On Friday, March 1, 2019, Democratic lawmakers in Colorado introduced Senate Bill 19-181, which, if enacted as proposed, would result in sweeping changes that would (i) re-envision the Colorado Oil and Gas Conservation Act to focus primarily on the protection of public health and the environment, (ii) fundamentally redefine the role and composition of the Colorado Oil and Gas Conservation Commission (“COGCC”), and (iii) elevate the power and level of input that local communities have with respect to oil and gas development activities. This far-reaching legislative proposal follows Colorado voters’ rejection of Initiative 97/Proposition 112 at the polls in November 2018 as well as the Colorado Supreme Court’s recent decision in COGCC v. Martinez, which affirmed the COGCC’s role in “foster[ing] the development of oil and gas resources” in Colorado. The newly-introduced legislation incorporates CCOGC reforms that were the subject of activist groups’ petitions to newly-elected Governor Polis in the wake of Initiative 97’s failure, and also constitutes a legislative response to the Colorado Supreme Court’s decision in Martinez. Governor Polis has announced his support for the proposed legislation, and hearings on S.B. 19-181 are set to begin Tuesday March 5,2019 in the Colorado Senate Committee on Transportation and Energy.

    It is vital that all oil and gas operators in Colorado familiarize themselves with this legislation. We have prepared a full analysis of S.B. 19-181 here. The full text of the proposed legislation is available here.

  • Colorado Supreme Court Affirms COGCC Role In Fostering Oil and Gas Development
    January 17, 2019

    On January 14, 2019, the Colorado Supreme Court issued an opinion in Colorado Oil and Gas Conservation Commission (“COGCC”) v. Martinez, No. 17SC297, clarifying the role of the COGCC in implementing the Colorado Oil and Gas Conservation Act (the “Act”). The Court had granted certiorari to determine whether the COGCC had “misinterpreted” its statutory authority under the Act “as requiring a balance between oil and gas development and public health, safety, and welfare.” The Court’s opinion confirms the common sense result that the COGCC is required “to foster the development of oil and gas resources” while “prevent[ing] and mitigat[ing] significant adverse environmental impacts . . . but only after taking into consideration cost-effectiveness and technical feasibility.”

    The Martinez lawsuit began in 2013 when Boulder, Colorado teen Xiuhtezcatl Martinez and a group of teenage Colorado citizens requested that the COGCC halt the issuance of any new drilling permits until studies from the best available science could demonstrate that the drilling did not pose a threat to human health or contribute to climate change. After COGCC denied the request, Martinez and the group appealed the decision in July 2014 to the Denver District Court. In February 2016, the district court affirmed COGCC’s refusal of the request, but on appeal in 2017, the Colorado Court of Appeals held that COGCC’s refusal was improper under the Act because, as that court reasoned, it requires COGCC to make and enforce regulations “in a manner consistent with” the protection of public health and safety—“a condition that must be fulfilled.” The Colorado Supreme Court’s opinion expressly rejects this reading in favor of one that requires the COGCC to balance various policy goals, including the development of oil and gas resources.

    While the Court’s opinion in Martinez is welcome news for the oil and gas industry, it is likely that it will not be the last chapter in this story. Legislation to codify the holding of the Colorado Court of Appeals was introduced in the Colorado General Assembly in January 2018. While that measure was postponed indefinitely by the Senate Agriculture, Natural Resources, & Energy Committee in March 2018, similar measures could be introduced in the future, and may find a more receptive audience in Colorado’s newly-elected General Assembly and Governor. Read the Court’s opinion in full here.

  • With Industry Support, Colorado Extends Setbacks from Schools Amid Continued Fight Over Broader Measures
    December 19, 2018

    On December 18, 2018, the Colorado Oil and Gas Conservation Commission (“COGCC”) voted unanimously to increase the setback distance from schools for new oil and gas wells or production facilities. The measure approved by the COGCC maintains Colorado’s existing 1,000-foot setback requirement, but measures the setback distance from newly-defined “school facilities,” which may include any “discrete facility or area . . . that students use commonly,” whether indoor or outdoor. Previously, Colorado had applied the 1,000-foot setback from school buildings.

    The COGCC’s approval of the school facility setback measure comes roughly six weeks after Colorado voters rejected Proposition 112 (formerly Initiative 97) at the polls. That measure sought to more broadly increase oil and gas facility setback distances on non-federal lands to 2,500 feet, thereby foreclosing oil and gas development on an estimated 54% of Colorado’s total land surface, including 85% of the non-federal lands in the state. Unlike Proposition 112, the school facility setback measure was supported by industry, including the Colorado Petroleum Council.

    While environmental groups also praised the COGCC’s approval of the school facility setback measure, it appears that the larger fight over oil and gas setbacks in Colorado will continue for the foreseeable future. 350 Colorado, a “grassroots network focused on taking action to stop climate change,” has released a petition that it intends to deliver to Governor-elect Jared Polis the day before he takes office. The petition calls for the increase of oil and gas facility setback distances to 2,500 feet and the legislative reform of the COGCC to change its focus away from “fostering” oil and gas development, as well as the suspension of further oil and gas permitting until the COGCC reforms have been achieved. Colorado Rising, the organization that sponsored Proposition 112, has also stated that it “definitely” plans another ballot initiative in 2020. While the COGCC’s approval of the school facility setback measure represents a significant moment of collaboration among the various stakeholders in Colorado, the broader debate over oil and gas facility setback distances in the state remains heated, and the potential consequences remain severe.

    Read the final draft school facility setback measure here.

  • Federal Court Issues Injunction Preventing Issuance of Pacific Offshore Hydraulic Fracturing Permits, Pending ESA and CZMA Consultations
    November 13, 2018

    On November 9, 2018, the United States District Court for the Central District of California issued an injunction preventing the Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement (collectively, the “Agencies”) from issuing any plans or permits for well stimulation treatments—namely, hydraulic fracturing and acidizing treatments—on the Pacific Outer Continental Shelf. In Environmental Defense Center et al. v. Bureau of Ocean Energy Management et al., plaintiffs the State of California and several environmental non-governmental organizations (“Plaintiffs”) challenged an Environmental Assessment (“EA”) prepared pursuant to the National Environmental Policy Act (“NEPA”) and issued by the Agencies examining the environmental impacts of well stimulation treatments on the Pacific Outer Continental Shelf. The Plaintiffs also alleged that the Agencies failed to complete necessary consultations under the Endangered Species Act (“ESA”) and Coastal Zone Management Act (“CZMA”) in connection with the Agencies’ proposed action. Both Plaintiffs and defendants (which include both the Agencies as well as industry intervenors) filed cross motions for summary judgment.

    The opinion issued on November 9 grants in part and denies in part each of the seven motions for summary judgment. Specifically, the court found that (i) the Agencies’ EA complies with NEPA, (ii) the Agencies completed the required ESA consultation with the National Marine Fisheries Service, (iii) the Agencies began, but did not complete, the required ESA consultation with the U.S. Fish and Wildlife Service (“FWS”), and (iv) the Agencies failed to undertake the required CZMA consultation with the California Coastal Commission (“CCC”), the state agency responsible for managing the ocean up to three miles away from land. Due to the failure to complete the consultations with FWS and CCC, the court issued an injunction prohibiting the Agencies from issuing any plans or permits for well stimulation treatments on the Pacific Outer Continental Shelf until these consultations have been completed. Importantly, the opinion makes clear that the Agencies may proceed to issue such plans and permits once these consultations have been completed. While it remains to be seen whether and when the Agencies will complete the required consultations, the opinion acknowledges that relatively few operations are expected to be delayed as a result of the injunction; throughout the course of the proceedings, the Agencies noted that “operators are only rarely expected” to request permits authorizing well stimulation treatments on the Pacific Outer Continental Shelf. Read the court’s opinion in full here.

  • Both Proposition 112 and Amendment 76 Rejected by Colorado Voters
    November 7, 2018

    On November 6, 2018, Colorado voters rejected both Proposition 112 and Amendment 76, sparing both the oil and gas industry and the state economy more broadly from uncertain and potentially disastrous consequences. Proposition 112 (formerly Initiative 97) sought to increase oil and gas facility setback distances on non-federal lands to 2,500 feet, which would have foreclosed oil and gas development on an estimated 54% of Colorado’s total land surface, including 85% of the non-federal lands in the state. Amendment 74 (formerly Initiative 108), which was widely viewed as a response by the oil and gas industry to Proposition 112, would have required that property owners be compensated for any reduction in property value due to any new governmental law or regulation.

    The final voting margins are not yet available. Colorado counties have until December 3 to compile their returns (including any ballots received by mail and any provisional ballots) and submit them to the Colorado Secretary of State. Both Proposition 112 and Amendment 76 will be officially rejected once the Colorado Secretary of State issues the final certification of the election results, an action likely to follow by mid-December.

    The voters of Colorado have decided that the status quo will prevail, for now. For oil and gas operators in the state, that means that Colorado’s current setback measure, which requires setback distances of 500 feet from “Residential Building Units” such as single-family residential homes, and 1,000 feet from “High Occupancy Building Units” such as schools, hospitals, and nursing homes, will continue to apply without change.

    The broader question moving forward is whether the voters’ rejection of Proposition 112 will be revisited by a future measure, leaving the Colorado oil and gas industry facing some degree of continued uncertainty even after voters’ sound rejection of Proposition 112. In certain jurisdictions, supporters of ballot initiatives seeking to place limits on oil and gas development have continued to push rejected measures in successive election cycles, even in the face of repeated failures. For example, voters going to the polls in Youngstown, Ohio on November 6, 2018 voted on a proposed ban on hydraulic fracturing and related oil and gas activities for the eighth time in five years, having rejected the prior seven attempts. It remains to be seen whether supporters of Proposition 112 in Colorado will pursue a similar approach in future elections and force Colorado voters to regularly reaffirm the results of the 2018 election going forward. Similarly, groups opposed to oil and gas activities in other jurisdictions may copy Proposition 112’s “setback as a sword” approach in an effort to disguise future efforts to all but ban oil and gas activities under the pretext of a “setback” measure that may appear more palatable to voters.

  • Colorado Secretary of State Certifies Initiatives 97 and 108 for November Ballot
    August 30, 2018

    On August 29, 2018, the Colorado Secretary of State (the “Secretary”) certified that Initiative 97, which would increase oil and gas development setback distances to 2,500 feet from “occupied structures” and “vulnerable areas,” had gathered a sufficient number of valid signatures to appear on the ballot this November.  The certification of Initiative 97 comes the day after the Secretary similarly announced that industry-backed Initiative 108 will also appear on the November ballot.  A direct response to Initiative 97, Initiative 108 would provide property owners with just compensation when a state or local government takes action diminishing the “fair market value” of their properties.  Initiative 108 appears designed to provide a compensation mechanism for oil and gas interests on private property that would no longer be exploitable because of setback distances such as those made effective and enforced as a result of Initiative 97, among other things.

    The certification of both Initiatives 97 and 108 sets the stage for a showdown on the November ballot which is sure to be preceded by 9 plus weeks of intense campaigning given the significant effects these measures would have on Colorado’s oil and gas industry as well as the state economy more broadly.  For example the Colorado Oil and Gas Conservation Commission has estimated that Initiative 97 would foreclose oil and gas development on 54% of Colorado’s total land surface, including 85% of the non-federal lands in the state.  Although both of Colorado’s gubernatorial candidates—Democrat Jared Polis and Republican Walker Stapleton—have announced publicly that they do not support Initiative 97, the fates of both Initiatives 97 and 108 will lie solely with the voters on November 6.

    Read more about the potential consequences of these ballot initiatives on the Colorado oil and gas industry on the Vinson & Elkins Environmental Blog here.

  • Supporters of Colorado Initiative 97 Submit Signatures to Secretary of State
    August 7, 2018

    On August 6, 2018, supporters of Initiative 97 in Colorado, which would increase oil and gas development setback distances to 2,500 feet from “occupied structures” and “vulnerable areas,” submitted approximately 171,000 signatures to Colorado Secretary of State Wayne Williams. In order to appear on the November ballot, Initiative 97 requires 98,492 valid signatures.

    Secretary Williams now has thirty days to determine if the 171,000 signatures submitted include 98,492 valid signatures. Although similar initiatives in 2016 initially submitted more than the required 98,492 signatures to the Secretary of State, about 25-28% of those signatures were deemed invalid, keeping those measures off the ballot. However, supporters of Initiative 97 have submitted over 60,000 more supporting signatures compared to the similar measures in 2016. It remains to be seen whether the 171,000 signatures submitted will include enough valid signatures for Initiative 97 to appear on the November ballot.

    Read more about the potential effects of Initiative 97 on the available land for oil and gas development in Colorado on the Vinson & Elkins Environmental Blog here.

  • Pennsylvania Issues Revised General Permits Regulating Methane Emissions from Unconventional Natural Gas Wells
    June 12, 2018

    On June 9, 2018, the Pennsylvania Department of Environmental Protection (“DEP”) released revised versions of General Plan Approval and/or General Operating Permits GP-5 and GP-5A (together, the “Revised General Permits”), applicable to “Natural Gas Compression Stations, Processing Plants, and Transmission Stations” and “Unconventional Natural Gas Well Site Operations and Remote Pigging Stations,” respectively. The Revised General Permits are aimed principally at regulating methane emissions from unconventional natural gas wells and midstream facilities, consistent with Governor Tom Wolf’s four point plan for reducing methane emissions announced in January 2016. The Revised General Permits are available to facilities with actual emissions less than 100 tons per year (“tpy”) of criteria pollutants (NOx, CO, SO2, PM10, and PM2.5), less than 50 tpy of VOCs, less than 10 tpy of any single hazardous air pollutant (“HAP”), and less than 25 tpy of total HAPs (use of the Revised General Permits is further restricted in Philadelphia, Bucks, Chester, Montgomery, or Delaware Counties to facilities with less than 25 tpy each of NOx and VOC emissions).

    The Revised General Permits, which will apply to new and modified sources constructed on or after August 8, 2018, require compliance with federal New Source Performance Standards (such as 40 C.F.R. Part 63 Subparts OOOO and OOOOa, although EPA has proposed a temporary stay of some of the OOOOa requirements but also include more stringent requirements as well. Specifically, the Revised General Permits contain “Best Available Technology” (“BAT”) standards that apply in addition to federal New Source Performance Standards. Of the thirteen BAT determinations in the GP-5 permit, nine impose requirements more stringent than the federal New Source Performance Standards; eight of the eleven BAT determinations in the GP-5A permit are more stringent than federal New Source Performance Standards. 

    Most notably, the Revised General Permits include a 200 tpy limit on methane emissions above which a BAT requirement for methane control applies–the first such numeric threshold applicable to methane emissions from unconventional natural gas wells and midstream facilities. While methane control techniques vary by emissions source, DEP considered “a closed vent system routed to a process or control” the primary control technique for emissions attributable to venting or process emissions, and a leak detection and repair (“LDAR”) program as the primary control technique for fugitive emissions. For fugitive emissions components, the Revised General Permits require LDAR within 60 days of startup and quarterly thereafter to comply with the BAT standard. Additional BAT requirements apply to storage vessels, tanker truck load-out operations, controllers, pumps, enclosed flares, well completion, combustion units, centrifugal natural gas compressors, fractionation process units, and sweetening units, among other sources addressed by GP-5 or GP-5A.

    It remains to be seen whether the Revised General Permits requiring control of methane emissions will have any impact on drilling activity in Pennsylvania, where operators drilled 809 new unconventional natural gas wells in 2017. Industry groups may also choose to bring litigation challenging the issuance of the Revised General Permits; an industry challenge to DEP’s Chapter 78a regulations also applicable to the unconventional industry has resulted in a stay that has put many of the Chapter 78a requirements on hold for over twenty months and counting. In the meantime, Governor Wolf’s efforts to reduce methane emissions continue. The remaining items of his four point plan call for promulgation of a regulation aimed at reducing methane emissions from leaks at existing oil and natural gas facilities and the development of best management practices (including LDAR programs) applicable to production, gathering, transmission and distribution lines.

  • OCC Issues New Seismicity Protocol
    March 2, 2018

    On February 27, 2018, the Oklahoma Corporation Commission (“OCC”) issued a new seismicity protocol for oil and gas operators in the South Central Oklahoma Oil Province (“SCOOP”) and the Sooner Trend Anadarko Basin Canadian and Kingfisher counties (“STACK”) plays. The new protocol requires all operators in a certain defined area to have access to a seismic array giving real-time seismicity readings; lowers the minimum level at which operators must take response actions from 2.5 magnitude to a 2.0 magnitude; and requires some operators to pause their operations for 6 hours at when readings exceed 2.5 magnitude, rather than 3.0 magnitude under the previous protocol. (Readings from the seismic array are necessary because tremors of less than magnitude 2.5 generally cannot be felt by humans on the ground surface.)

    The new protocol is separate from existing rules addressing wastewater injection in the Arbuckle formation, in the northern area of Oklahoma. Drilling activities in the SCOOP and STACK plays have far less water associated with them than similar activities in the Arbuckle, where the disposal of produced water remains Oklahoma regulators’ “larger concern” in addressing seismic activity, according to an OCC news release. Indeed, seismic activity in the SCOOP and STACK plays is “relatively rare and smaller on average than [that] linked to injection activity. Most importantly, the risk of such events appears to be manageable,” according to the OCC. Read the news release in full here.

  • Federal Court’s Order Sends BLM Methane Rule into Force, For Now
    March 1, 2018

    On February 22, 2018, the United States District Court for the District of California granted a preliminary injunction on the Bureau of Land Management’s (“BLM”) attempt to delay certain requirements of the 2016 Waste Prevention Rule (“Waste Prevention Rule”) for one year. In December 2017, BLM finalized a rule to delay the requirements of the Waste Prevention Rule originally effective January 17, 2018 until January 17, 2019 (the “Postponement”). The states of California and New Mexico (California et al. v. BLM et al., Case No. 17-cv-07186) and several environmental groups (Sierra Club et al. v. Zinke et al., Case No. 17-cv-07187) sued to enjoin the Postponement. 

    The states and the environmental groups filed motions for preliminary injunctions, the court held a hearing on February 14, 2018, and the court issued its order the following week. In granting a preliminary injunction, the court considered only the Postponement and not BLM’s February 12, 2018 proposed rule intended to replace the Waste Prevention Rule (the “Proposed Replacement”). The comment period for the Proposed Replacement is ongoing and will end on April 23, 2018. 

    The separate legal challenge to the validity of the Waste Prevention Rule in United States District Court for the District of Wyoming (Western Energy Alliance et al. v. Secretary of the U.S. Dep’t of the Interior et al., Case No. 16-cv-00280) remains stayed, although two groups of states have already filed motions with the court to lift the stay. The joint motion of North Dakota and Texas seeks to establish an expedited schedule for further proceeding, while the motion of Wyoming and Montana requests that the court “immediately suspend the implementation deadlines in the Waste Prevention Rule until either the Bureau of Land Management promulgates the replacement rule or the Court rules on the merits of the Petitions for Review.”  For now, the Waste Prevention Rule, including the leak detection and repair, emission reduction, and reporting requirements (originally effective as of January 17, 2018) is in effect.

  • BLM Proposes to Eliminate Emissions-Related Provisions of Currently-Postponed Waste Prevention Rule
    February 21, 2018

    On February 12, 2018, the Bureau of Land Management (“BLM”) released a pre-publication version of a proposed rule (the “Proposed Rule”) to modify the 2016 Waste Prevention Rule (the “Waste Prevention Rule”). The proposed modifications to the Waste Prevention Rule include the elimination of provisions aimed at reducing methane emissions from oil and gas facilities on federal lands. Compliance with these provisions of the Waste Prevention Rule has already been postponed until January 2019 pursuant to a final rule (the “Postponement”) promulgated by BLM on December 8, 2017, though the Postponement remains subject to pending judicial review.

    BLM’s Waste Prevention Rule, initially promulgated in November 2016, covers a number of methane emissions sources associated with oil and gas production activities on federal lands, including natural gas emissions from venting or flaring, gas leaks from equipment and facilities located at the well site, and well drilling and completions. The Proposed Rule would eliminate many of the requirements aimed at reducing these emissions, and modify several others to reflect an approach similar to that in effect prior to the promulgation of the Waste Prevention Rule. For example, the Proposed Rule would eliminate the requirement that operators prepare “Waste Minimization Plans” when submitting an Application for Permit to Drill, as well as operational and equipment-related requirements applicable to well drilling operations, well completions, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. Pursuant to the Proposed Rule, the Waste Prevention Rule’s requirements related to gas capture, downhole well maintenance, liquids unloading, and measuring/reporting volumes of gas vented and flared would be “modified and/or replaced” to reflect the policies set forth in BLM’s NTL-4A, which governed venting and flaring from BLM-administered leases prior to the promulgation of the Waste Prevention Rule.

    BLM has justified its proposed rule on “overlap” with the Environmental Protection Agency’s (“EPA”) New Source Performance Standards (“NSPS”) and a revised cost-benefit analysis, which concluded that “the value of the conserved gas would not outweigh the costs” of the regulation. Read more about BLM’s justification for the Proposed Rule here.

    Meanwhile, the Postponement remains in effect, though it is subject to a pending judicial challenge brought by the states of California and New Mexico (California et al. v. BLM et al., Case No. 17-cv-07186) and several environmental groups (Sierra Club et al. v. Zinke et al., Case No. 17-cv-07187) in the United States District Court for the Northern District of California. Both the states and the environmental groups have filed motions for a preliminary injunction that would reinstate the Waste Prevention Rule’s original January 2018 compliance deadlines. The court heard oral arguments on these motions on February 14, 2018. A separate legal challenge to the validity of the 2016 Waste Prevention Rule brought by several industry groups and states also remains pending in Western Energy Alliance et al. v. Secretary of the U.S. Dep’t of the Interior et al., Case No. 16-cv-00280 in the United States District Court for the District of Wyoming. In that case, the court granted a motion to stay the case pending BLM’s rulemaking to rescind or revise the Waste Prevention Rule, and BLM continues to file status updates with the court in accordance with the court’s order granting the stay.

    The Proposed Rule will remain open for public comment for a 60-day period following its publication in the Federal Register. BLM has stated that it intends to conclude this rulemaking effort within the period during which compliance with the Waste Prevention Rule has been suspended pursuant to the Postponement. Nonetheless, the pending motions seeking preliminary injunctions in the litigation challenging the Postponement create continued uncertainty for operators on federal lands, raising the prospect that the Waste Prevention Rule’s original January 2018 compliance deadlines could be reinstated — at least temporarily while BLM finalizes the Proposed Rule — by court order.

  • BLM Rescinds 2015 Hydraulic Fracturing Rule
    January 2, 2018

    On December 29, 2017, the Bureau of Lang Management (“BLM”) issued a final rule (the “Rescission”) rescinding in its entirety the agency’s 2015 final rule regulating hydraulic fracturing activities on Federal and Indian lands (the “2015 Rule”). The 2015 Rule (link to 2015 white paper on fracking website) included a comprehensive set of well-bore integrity requirements, standards for the interim storage of recovered waste fluids, mandatory notifications and waiting periods for key parts of the fracturing process, and chemical disclosure requirements. However, these requirements had not yet taken effect as a result of a stay issued in connection with the ongoing judicial challenges to the 2015 Rule. Pursuant to the Rescission, BLM’s hydraulic fracturing regulations (43 CFR Part 3160) in effect prior to effective date of the of 2015 Rule (June 24, 2015) will now govern hydraulic fracturing activities on Federal and Indian lands going forward, effective immediately. 

    In the preamble to the Rescission, BLM explains that rescission of the 2015 Rule is preferable to the 2015 Rule because it will “relieve operators of duplicative, unnecessary, costly and unproductive regulatory burdens.”  Specially, BLM estimates the Rescission will result in savings of $9,690 in compliance costs per well. The preamble further explains that the agency reviewed incident reports associated with hydraulic fracturing activities on Federal and Indian lands since December 2014 and found a “rarity of adverse environmental impacts that occurred from hydraulic fracturing operations since promulgation of the 2015 [R]ule.”  BLM concludes in the preamble that the BLM’s own pre-existing regulations, coupled with state/tribal oversight and regulations, mitigate such risks. 

    The preamble also explains that the Rescission “eliminates the need for further litigation about BLM’s statutory authority.”  In litigation challenging the 2015 Rule, the District Court for the District of Wyoming concluded (link to June 22, 2016 frack flash) that regulating hydraulic fracturing activities was outside the BLM’s statutory authority. Although the United States Court of Appeals for the Tenth vacated the District Court’s final order, plaintiffs in that case have moved for rehearing or reconsideration en banc. These proceedings are pending, and it remains to be seen what effect the Rescission will have with respect to the continuing litigation regarding the 2015 Rule. 

    While the Rescission is effective immediately, judicial challenges to the Rescission are likely. Read the Rescission in full here.

  • BLM Finalizes Postponement of Waste Prevention Rule
    December 13, 2017

    On December 8, 2017, the Bureau of Land Management (“BLM”) published a final rule (the “Postponement”) postponing certain requirements of the 2016 Waste Prevention Rule (“Waste Prevention Rule”) for one year. BLM’s Postponement reflects the completion of BLM’s latest effort to delay the requirements of the Waste Prevention Rule after a court in the Northern District of California vacated BLM’s previous attempt to postpone the effective dates of the rules through alternative procedures. 

    BLM’s Waste Prevention Rule, initially promulgated in November 2016, covers a number of methane emissions sources associated with oil and gas production activities on federal lands, including natural gas emissions from venting or flaring, gas leaks from equipment and facilities located at the well site, and well drilling and completions. While the Waste Prevention Rule called for operators to submit “waste minimization” plans by January 2017, the Rule’s leak detection and recovery, emission reduction, and reporting requirements were scheduled to go into effect on January 17, 2018. BLM issued a proposed rule in October 2017 proposing to extend the Waste Prevention Rule’s January 2018 effective dates to January 2019. The proposed rule was open to public notice and comment for a 30-day period concluding November 6, 2017. The Postponement formally promulgates the October 2017 proposed rule, extending the Waste Prevention Rule’s original January 17, 2018 effective dates to January 17, 2019. 

    The Postponement is currently in effect, but remains subject to judicial challenge in the future. Any such future judicial challenge could also raise a prospective stay of the Postponement, which could bring the original 2016 Waste Prevention Rule deadlines back into effect pending the court’s resolution of the judicial challenge to the Postponement. Meanwhile, a separate legal challenge to the validity of the 2016 Waste Prevention Rule brought by several industry groups and states remains pending in Western Energy Alliance et al. v. Secretary of the U.S. Dep’t of the Interior et al, Case No. 16-cv-00280 in the U.S. District Court for the District of Wyoming. In that case, the Federal Respondents have filed a Motion to Dismiss, or, in the alternative, for a Stay of Proceedings in light of the Postponement.

  • DRBC Proposed Rule Would Ban High-Volume Hydraulic Fracturing
    December 1, 2017

    On November 30, 2017, the Delaware River Basin Commission (“DRBC”) published a proposed rule that, if finalized, would prohibit “high-volume hydraulic fracturing” within the Delaware River Basin.  The proposed rule reflects the DRBC’s conclusion that “high volume hydraulic fracturing poses significant, immediate and long-term risks to the development, conservation, utilization, management, and preservation of the water resources of the Delaware River Basin.”  The Delaware River Basin extends into four northeastern states and includes seventeen counties in Eastern Pennsylvania, many of which lie above the Marcellus Shale formation.

    The proposed rule defines “high-volume hydraulic fracturing” as fracturing operations that use “a combined total of 300,000 or more gallons of water during all stages in a well completion . . . whether the water is fresh or recycled and regardless of the chemicals or other additives mixed with the water.”  This definition is likely to capture most hydraulic fracturing operations.   For example, the preamble to proposed rule states that the average hydraulically fractured natural gas well in the nearby Susquehanna River Basin injected 4.3 million gallons of water from 2008-2013; similarly, the preamble cites the United States Environmental Protection Agency’s 2016 hydraulic fracturing study, which concluded that the median volume of water used per well fracturing event in Pennsylvania between January 2011 and February 2013 was 4.18 million gallons.

    In addition to the proposed ban on high-volume hydraulic fracturing, the proposed rule would also discourage the exportation of waters from the Delaware River Basin “to support hydraulic fracturing outside the Basin,” require an assessment of alternatives before allowing the importation of produced water into the Delaware River Basin, and require DRBC approval for produced water treatment within the Delaware River Basin.

    The DRBC is accepting comments on the proposed rule through February 28, 2018 at 5 PM.  In addition, the DRBC will convene a series of public hearings on the proposed rule on January 23, 2018 in Waymart, Pennsylvania and on January 25, 2018 in Philadelphia, Pennsylvania.  Read the proposed rule in full here.

  • Court Vacates BLM’s Postponement of Obama-Era Waste Prevention Rule
    October 10, 2017

    On October 4, 2017, in a consolidated decision for Sierra Club, et al. v. Zinke, et al., No. 17-cv-03885, and State of California, et al. v. United States Bureau of Land Management, et al., No. 17-cv-03804, the U.S. District Court for the Northern District of California vacated the Bureau of Land Management’s (”BLM”) postponement of BLM’s 2016 final rule entitled “Waste Prevention, Production Subject to Royalties, and Resource Conservation” (the “Waste Prevention Rule”). The district court held that BLM’s postponement did not comply with Section 705 of the Administrative Procedure Act. The decision vacates BLM’s June 15, 2017 notice postponing the Waste Prevention Rule’s January 17, 2018 compliance deadlines pending a decision in Western Energy Alliance et al. v. Secretary of the U.S. Dep’t of the Interior et al, Case No. 16-cv-00280 in the U.S. District Court for the District of Wyoming, in which several industry groups and states have challenged the finalized Waste Prevention Rule’s legal validity. 

    BLM’s Waste Prevention Rule, initially promulgated in November 2016, covers a number of methane emissions sources associated with oil and gas production activities on federal lands, including natural gas emissions from venting or flaring, gas leaks from equipment and facilities located at the well site, and well drilling and completions. While the Waste Prevention Rule called for operators to submit “waste minimization” plans by January 2017, the Rule’s leak detection and recovery, emission reduction, and reporting requirements are scheduled to go into effect on January 17, 2018. 
    The BLM Waste Prevention Rule is currently in effect and compliance with those portions of the rule with initial compliance deadlines of January 2018 will be required absent additional administrative or judicial action in the interim. Several such actions remain possible, and Department of Interior officials have previously pledged to “suspend, revise or rescind” the rule in light of its “significant regulatory burden.” Primary among these efforts is BLM’s October 5, 2017 proposed rule that would extend the Waste Prevention Rule’s January 2018 deadlines to January 2019. The comment period for this proposed rule is currently open through November 6, 2017, leaving BLM with limited time following the comment period to promulgate a final rule in advance of the January 2018 deadlines. In addition, industry’s judicial challenge to the Waste Prevention Rule in Western Energy Alliance remains pending. Finally, appropriations bill HR 3354, which has passed the House of Representatives and has been placed on the Senate Legislative Calendar, would, if signed into law, prohibit BLM from using its funds to enforce the Waste Prevention Rule.

  • Scotland Expected to Ban Fracking
    October 9, 2017
    United Kingdom

    On October 3, 2017 Scotland’s Energy Minister Paul Wheelhouse announced an effective ban on hydraulic fracturing. Hydraulic fracturing had already been prohibited in Scotland under a temporary moratorium in 2015 as a result of campaigns by various environmental and community groups. This was followed by a series of environmental and economic reports on fracking in 2016, as well as a full public consultation in early 2017. The environmental reports found that fracking’s impact on global emissions would be neutral, that the probability of an earthquake that can be felt is small, and that there is “inadequate” evidence to reach firm conclusions regarding the activity’s health impacts. On the economy, the reports determined that fracking could create anywhere from 470 to 3,100 jobs and contribute from £100 million to £4.6 billion to the Scottish economy through the year 2062. Reports aside, the primary driver of the ban appears to be the public consultation, which the energy minister described as showing “overwhelming” opposition. Indeed, 99% of the 60,000 respondents supported the ban. While the decision to ban fracking will not be final until Parliament endorses the ban in a vote after the October recess, commentators predict that the vote will be a formality.

  • D.C. Circuit Strikes Down EPA’s 90-day Stay – New Standards for Oil & Gas Sector
    August 7, 2017

    On July 3, 2017, in Clean Air Council, et al. v. E. Scott Pruitt, No. 17-1145, the D.C. Circuit struck down EPA’s 90-day stay on the June 3, 2016 final rule entitled “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources,” which amended and established updated new source performance standards (“NSPS”) for the oil and natural gas sector. This final rule was codified in EPA’s NSPS regulations as Subpart OOOOa to 40 C.F.R. Part 60 or “Quad Oa.” The D.C. Circuit later recalled its mandate in Clean Air Council, et al. v. E. Scott Pruitt, No. 17-1145, giving EPA until July 27, 2017 to file a petition for rehearing or petition for rehearing en banc. On July 31, 2017, after EPA failed to file a timely petition, the D.C. Circuit reissued its mandate. Consequently, all Quad Oa provisions are now in effect.

    On June 16, 2017, the United States Environmental Protection Agency (EPA) published a proposed rule that would stay for two years parts of Quad Oa. EPA’s proposed two-year stay was intended to be an extension of the 90-day stay that EPA announced on June 3, 2016 to delay implementation of Quad Oa and that was struck down by the D.C. Circuit. Like the 90-day stay, the proposed two-year stay covers aspects of Quad Oa related to leak detection and reporting requirements for (1) fugitive emissions at well sites and compressor stations and (2) fugitive emissions from pneumatic pumps as well as (3) the requirement of a professional engineer certification in relation to the closed vent system design and capacity for a number of affected facilities (e.g., centrifugal compressors, reciprocating compressors, pneumatic pumps, and storage vessels). If finalized, the proposed two-year stay would effectively suspend Quad Oa’s compliance deadlines. In addition to proposing a two-year stay on these aspects of Quad Oa, EPA’s July 16, 2017 proposed rule would include a review of Quad Oa in its entirety. EPA has held open the June 16, 2017 proposed comment rule period until August 9, 2017 because it received and granted a request for hearing on the proposed rule. EPA held the hearing in question on July 10, 2017.

    When the D.C. Circuit issued its mandate, two main deadlines under Quad Oa became effective. First, Quad Oa requires that facilities covered by the rule conduct an initial monitoring survey by June 3, 2017. 40 C.F.R. § 60.5397a(f). Second, Quad Oa requires facilities covered by the rule to submit their initial annual monitoring by 90 days after the “initial compliance period” defined under the rule ended. This compliance period ended, at the latest, on August 2, 2017, meaning that facilities covered by Quad Oa have 90 days from that date to submit their initial annual monitoring report. See 40 C.F.R. §§ 60.5420a and 60.5410a. It remains to be seen (1) whether EPA will finalize its proposed two-year stay before the reporting deadline in Quad Oa passes and (2) whether EPA’s two-year stay withstands judicial scrutiny.

  • TAMEST Report Concludes that Hydraulic Fracturing Has Not Induced Seismicity in Texas
    June 20, 2017

    On June 19, the Academy of Medicine, Engineering, and Science of Texas (“TAMEST”) issued its report titled Environmental and Community Impacts of Shale Development in Texas. The report includes several noteworthy findings, including that:

    • Potentially-induced, felt seismicity in Texas to date has been associated with Class II disposal wells, not with hydraulic fracturing operations; 
    • Direct fracturing into drinking water zones has not been observed in Texas, and such a result is unlikely given the depth separation between oil-bearing formations and drinking water zones; an
    • Shale development “primarily contributes positively to local, regional, and state economies.”

    In addition to the above, the report includes other findings and recommendations on geology and earthquake activity, land resources, air quality, water quantity and quality, transportation, and economic and social impacts.  

    Other of the report’s recommendations call on the industry to more closely track the environmental and ecological impact of shale operations, and make information surrounding shale development more transparent. For example, as to land resources, the report suggests that “baseline land and habitat conditions at the oil and gas play level should be characterized, and changes to wildlife populations and vegetation should be tracked over time where there are opportunities on both private and public lands,” and that “the existing, nonproprietary information about land impacts of shale development that is collected and evaluated by multiple state and federal agencies should be assembled and made available online to the public.”

    The report is the culmination of the efforts of TAMEST’s Shale Task Force, which was convened in 2015 and consists of multiple academic and scientific representatives from institutions and organizations throughout Texas. Read the report in full here.

  • EPA Proposes 2-Year Stay on Key Parts of Quad Oa — the 2016 Methane NSPS Rule for the Oil and Gas Industry
    June 19, 2017

    On June 13, 2017, the United States Environmental Protection Agency (EPA) published a proposed rule that would stay for two years parts of EPA’s June 3, 2016 final rule entitled “Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, and Modified Sources,” which amended and established updated new source performance standards (NSPS) for the oil and natural gas sector. This final rule was codified in EPA’s NSPS regulations as Subpart OOOOa to 40 CFR Part 60 or “Quad Oa.” Detailed information about Quad Oa can be found here.

    EPA has been signaling some form of stay on parts of Quad Oa for several months in connection with President Trump’s March 28, 2017 Executive Order on Promoting Energy Independence and Economic Growth (Climate Change Executive Order), which specifically called for EPA to review Quad Oa in connection with a mandate for agencies to review any regulations that “potentially burden the safe, efficient development of domestic energy sources.” On April 18, 2017, EPA Administrator Scott Pruitt announced by letter that EPA would be convening regulatory proceedings to reconsider Quad Oa. On June 5, 2017, EPA published a notice in the Federal Register stating that EPA would be staying for three months certain aspects of Quad Oa. On June 13, 2017, EPA issued its proposed rule requesting a two-year stay on parts of Quad Oa to allow EPA to review Quad Oa in connection with several petitions for reconsideration submitted to EPA regarding Quad Oa in August 2016.

    EPA’s proposed rule does not stay Quad Oa in its entirety but instead stays only the parts of Quad Oa that relate to (1) fugitive emissions at well sites and compressor stations, (2) emissions from pneumatic pumps, and (3) the requirement of a professional engineer certification in relation to the closed vent system design and capacity for a number of affected facilities (e.g., centrifugal compressors, reciprocating compressors, pneumatic pumps, and storage vessels).

    On June 5, 2017, several environmental non-governmental organizations (ENGOs) filed suit in the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) in connection with EPA’s three-month stay of Quad Oa. It appears likely that these ENGOs will seek to broaden this suit or file a separate suit in connection with EPA’s proposed two-year stay of Quad Oa. As noted elsewhere on the Vinson & Elkins Climate Change Blog, this litigation represents only the beginning of “the legal battles that will certainly ensue” in relation to agencies’ implementation of the Climate Change Executive Order.

  • Environmental Groups Seek to Overturn Administrative Stay of Quad Oa Rules
    June 13, 2017

    On Monday, June 5th, multiple environmental groups filed an emergency motion seeking a stay of EPA’s decision to delay and reconsider certain provisions of the New Source Performance Standards for the oil and gas industry, also known as “Quad Oa,” finalized in June 2016. The motion followed on the heels of EPA’s June 3rd Federal Register publication granting reconsideration of certain rule requirements and delaying the effective date of certain portions of the rule by 90 days. Quad Oa aims to decrease methane emissions from new and existing oil and gas sources and was considered a cornerstone of President Obama’s climate change initiative. A key aspect of the rule is its requirement that oil and gas companies implement a leak detection and repair program to monitor equipment leaks from well sites and other components.

    Under the rule, owners and operators were required to complete their first round of monitoring by June 3, 2017. The June 3rd Notice would retroactively stay the leak detection and repair program, as well as other requirements, for a period beginning on June 2nd through August 31st. The motion notes that a second notice, proposing to extend the stay for an indeterminate period of time, is pending at the Office of Management and Budget and that these actions are Administrator Pruitt’s “first steps” towards suspending, revising, or rescinding the entire rule. In addition to staying the leak detection and repair requirements, the Notice also stays the standard for pneumatic pumps and requirements that a professional engineer certify the proper installation of closed vent systems used to comply with certain standards in the 2016 rule.

    The motion filed by the coalition of environmental groups challenges EPA’s authority to issue the stay, arguing that “[p]romulgated rules remain in effect unless and until they are validly challenged through the Clean Air Act’s enhanced rule-making procedures.” The groups argue further that EPA’s issuance of the stay does not meet the statutory requirements of a “reconsideration proceeding” allowed by the Clean Air Act. In the alternative, the environmental groups claim that the administrative stay is arbitrary and capricious because it is overbroad, because the Administrator failed to consider whether industry would be irreparably harmed by adhering to the original compliance dates, and because the Administrator did not assess the damage to public health and welfare that would be caused by the stay. It remains to be seen how the D.C. Circuit will respond to the emergency motion. In the meantime, owners and operators must determine whether to proceed as if the original compliance dates will remain in effect or to delay the implementation of their leak detection and repair programs pending further action by the court.  Read the emergency motion in full here.

  • DOE Solicits Input on New State Water Policy Database
    June 8, 2017

    On June 5, the Department of Energy (“DOE”) published a Request for Information (“RFI”) in the Federal Register soliciting input on a new Energy-Water Nexus State Policy Database (the “Database”), a draft version of which is available at The intent of the Database is to provide “information about state-level water policies and programs that are relevant to energy systems in the United States.” The current draft version of the Database includes over 1,700 policy entries addressing topics such as discharge permitting regimes, underground injection control permitting, water rights, water quality standards, and water-related regulations applicable to hydraulic fracturing and electric generating operations. DOE is soliciting input on several aspects of the draft Database, including, most notably, the quality and completeness of the policy descriptions available via the Database and the availability of other data sources that could be connected to or coordinated with the Database. Stakeholders may submit responses to the RFI through August 4, 2017.

  • Governor Signs Bill Banning Hydraulic Fracturing in Maryland
    April 5, 2017

    On April 4, 2017, Governor Larry Hogan signed into law a bill that makes Maryland the third state (following New York and Vermont) to ban hydraulic fracturing. Maryland’s ban is particularly notable as the Marcellus Shale formation extends into the western part of the state. Hydraulic fracturing has been under various moratoria in Maryland since June 2011, when former Governor Martin O’Malley issued an Executive Order directing the Maryland Department of the Environment (“MDE”) and the Maryland Department of Natural Resources to study economic, environmental, and public health issues related to horizontal drilling and hydraulic fracturing in the Marcellus Shale. The final study, which was released in November 2014, concluded that any environmental or health risks from hydraulic fracturing could be adequately managed through regulatory measures, but, shortly after that study’s release, Maryland enacted a two-year moratorium that prevented the MDE from issuing any drilling permits for hydraulic fracturing before October 1, 2017. The new permanent ban on hydraulic fracturing takes effect on that same date—October 1, 2017. Read the full text of Senate Bill 740 here.

  • Federal Court Dismisses Sierra Club’s Claim for Injunctive Relief Related to Oklahoma Seismicity
    April 5, 2017

    On April 4, 2017, Western District of Oklahoma Judge Stephen Friot dismissed an action brought under the Resource Conservation and Recovery Act (“RCRA”) by the Sierra Club against four deep fluid injection well operators. The plaintiff alleged that the defendants’ use of wastewater injection wells presented an “imminent and substantial endangerment to health or the environment” in violation of RCRA because it supposedly causes “waste-induced earthquakes.” The Sierra Club sought a wide range of injunctive relief, asking the court to order defendants to substantially reduce the volume of wastewater they inject into disposal wells, reinforce vulnerable structures, and establish a seismic activity monitoring center to further analyze (and predict) the potential for seismic effects of underground injection of oilfield wastes. 

    Judge Friot granted defendants’ motions to dismiss under the Burford abstention and primary jurisdiction doctrines before reaching defendants’ substantive RCRA arguments. Pursuant to the Burford abstention doctrine, federal courts may decline to interfere with proceedings or orders of state administrative agencies where timely and adequate state-level review is available. The Court reasoned that the Oklahoma Corporation Commission (“OCC”) “has established and is operating its own authorized program to regulate these wells” and “has taken action to address the seismic activity which plaintiff maintains is linked to the Arbuckle disposal wells.” Oklahoma law also provides that any person affected by an OCC order may apply to the OCC for repeal, amendment, modification, or supplement of that order. The court also held that the OCC has primary jurisdiction over the harm alleged by the plaintiff for similar reasons. Judge Friot reasoned that the OCC was better equipped than the court to address seismicity concerns associated with fluid injection activities, and has “taken a series of actions, in response to seismic activity, to reduce the volume of wastewater injected into disposal wells.” The court also found that the OCC “has demonstrated diligence in resolving” seismicity issues, and, given its “scientific and technical expertise,” is the appropriate body to grant the type of injunctive relief requested by the plaintiff.

    In closing, Judge Friot described the reality of being an Oklahoma resident – implying that he too lived with the tremors. “Every night, more than a million Oklahomans go to bed with reason to wonder whether they will be awakened by the muffled boom which precedes, by an instant, the shaking of the ground under their homes.” Finally, Judge Friot expressed his confidence in the seriousness of the OCC’s regulatory efforts, by noting that “responding to this earthquake activity is serious business, requiring serious regulatory action. The record in this case plainly demonstrates that the Oklahoma Corporation Commission has responded energetically to that challenge.”

    Read the order dismissing plaintiff’s complaint in Sierra Club v. Chesapeake Operating, LLC, No. 5:16-cv-00134, here.

  • DEP Concludes Seismic Activity in Pennsylvania “Likely Correlated” with Hydraulic Fracturing
    February 22, 2017

    On Friday, February 17, the Pennsylvania Department of Environmental Protection (“DEP”) published a report concluding that four specific low-magnitude seismic events that occurred on April 25, 2016 “were likely correlated” with hydraulic fracturing activity. The seismic events at issue were registered on the Pennsylvania Seismic Network and consisted of a series of four “microseismic events” at magnitudes unlikely to be noticed by humans. The report concludes that these seismic events showed a “marked temporal/spatial relationship” to hydraulic fracturing activities at a nearby well pad, but ultimately cautions that “there is no definitive geologic association of events at this time.” 

    Nonetheless, the DEP’s report includes several recommendations that will likely have an impact on how operators conduct their fracturing activities in certain areas of the Utica Shale formation. The technique used at the time of the April 2016 seismic activity is called “zipper fracturing,” and involves conducting hydraulic fracturing operations concurrently at two horizontal wellbores that are parallel and adjacent to each other. The DEP report describes that DEP and the operator agreed to a seismic monitoring plan in November 2016 that requires the operator of the well at issue to (i) discontinue the use of the “zipper fracturing” technique during any future completions when there is less than a quarter mile between lateral portions of adjacent wellbores; (ii) maintain its own seismic network to detect events; and (iii) adopt a specific seismic reporting and response plan. The plan also requires the operator of the well at issue to abide by a “traffic light” system, whereby the operator must, among other things, (i) notify DEP of seismic activity above 1.0 magnitude within 6 miles of a wellbore path, (ii) suspend operations if three seismic events between 1.5 and 1.9 magnitude occur within three consecutive days within 3 miles of a wellbore path, and (iii) shut down well operations if a seismic event magnitude 2.0 or greater occurs within 3 miles of a wellbore path. The report recommends that other operators in North Beaver, Mahoning, and Union Townships in Pennsylvania follow similar plans.

    The report’s “traffic light” system recommendations are particularly notable because they apply at conservative levels of seismicity compared to other jurisdictions. For example, Well Completion Seismicity Guidance applicable to operators in the Scoop and Stack plays published by the Oklahoma Corporation Commission in December 2016 requires reporting of seismicity at magnitude 2.5 or greater within 1.25 miles of fracturing operations, a temporary pause in operations at magnitude 3.0 or greater, and the suspension of operations at magnitude 3.5 or greater. It remains to be seen whether the report’s recommendations will affect the level of hydraulic fracturing activity in the affected townships.

  • EPA Releases Final Assessment of Fracking Impacts on Drinking Water
    December 13, 2016

    On December 13, 2016, the United States Environmental Protection Agency (“EPA”) released its Final Assessment of the Potential Impacts of Hydraulic Fracturing for Oil and Gas on Drinking Water Resources. Issuance of the final report comes over eighteen months after EPA released a draft report for external review in June 2015, and approximately a year after an EPA Science Advisory Board panel released its initial recommendations regarding the closely-followed hydraulic fracturing study. Pursuant to those recommendations, the final report reflects the removal of the draft report’s overarching conclusion that EPA “did not find evidence that” hydraulic fracturing activities “have led to widespread, systemic impacts on drinking water resources in the United States.” In an accompanying set of “ Questions and Answers about EPA’s Hydraulic Fracturing Drinking Water Assessment,” EPA explains that its scientists concluded that the conclusion of the draft report “could not be quantitatively supported” and that it did not “clearly communicate the findings of the report.” Instead, the final report concludes that “hydraulic fracturing activities can impact drinking water resources in the United States under some circumstances.” 

    Importantly, however, EPA’s findings that underlie the final report’s conclusion are generally consistent with those set forth in the June 2015 draft report. For example, both the draft report and the final report identify above- and below-ground mechanisms in the hydraulic fracturing water cycle that “have the potential to impact drinking water resources.” Similarly, both the draft report and the final report characterize the number of identified cases of drinking water resource contamination as “small” in comparison to the number of hydraulically fractured wells in the United States. Finally, consistent with the draft report, most of the small number of “impacts on drinking water resources” identified by EPA appear to be unrelated to fracturing activity itself. Nonetheless, like the draft report, the final report identifies the “potential for hydraulic fracturing fluids . . . to reach underground drinking water resources” via the fracture network. On this topic, the final report identifies with more specificity those areas in which hydraulic fracturing activity has occurred within underground drinking water resources—namely “in some areas in the western United States (e.g., the Wind River Basin near Pavillion, Wyoming, and the Powder River Basin of Montana and Wyoming).” 

    Unlike the draft report, the final report includes a list of “combinations of activities and factors” associated with hydraulic fracturing activity that EPA concludes “are more likely than others to result in more frequent or more severe impacts” to drinking water resources. That list consists of:

    • Water withdrawals in times or areas of low water availability, particularly in areas with limited or declining groundwater resources;
    • Spills during the management of hydraulic fracturing fluids, chemicals, or produced water that reach groundwater resources;
    • Injection of hydraulic fracturing fluids into wells with inadequate mechanical integrity, allowing gases or liquids to reach groundwater resources;
    • Injection of hydraulic fracturing fluids directly into groundwater resources (a practice primarily associated with coalbed methane production)
    • Discharge of inadequately treated hydraulic fracturing wastewater to surface water resources; and
    • Disposal or storage of hydraulic fracturing wastewater in unlined pits, resulting in contamination of groundwater resources.

    Notably absent from this list of increased risk activities is hydraulic fracturing of deep shale formations. Indeed, the final report acknowledges that the presence of “thousands of feet of rock between hydraulically fractured rock formations and underground drinking water resources can reduce the frequency of impacts on drinking water resources” during well injection. Read the final report in full here.

    For more insight on water laws and regulation, visit V&E’s Water Blog.

  • Two Lawsuits Relating to Induced Seismicity Filed in Oklahoma
    November 23, 2016

    Two lawsuits recently filed in courts in Oklahoma allege claims relating to induced seismicity following a September 8, 2016 earthquake, which measured magnitude 5.8 and had an epicenter approximately 8 miles northwest of Pawnee, Oklahoma.  That quake was the largest reported in Oklahoma since seismic record-keeping began.

    The first case, filed in Oklahoma state court on November 17, is a putative class action brought by an Oklahoma resident against 27 oil and gas companies that have engaged in injection well operations near Pawnee, 25 of which are unnamed in the class action petition. The petition generally alleges that defendants’ disposal of fracking wastewater in injection wells caused dozens of earthquakes near Pawnee from September through November 2016 (including the magnitude 5.8 earthquake on September 3) and asserts claims of absolute liability for ultrahazardous activities, negligence, private nuisance, and trespass.  The petition seeks damages for physical damage to real and personal property, market value losses to real property, and punitive damages, and alleges that the defendants are jointly and severally liable for such damages.  Read the Class Action Petition in James Adams et al. v. Eagle Road Oil LLC et al., case number CJ201678, in the District Court of Pawnee County, Oklahoma here.

    The second case, brought by the Pawnee Nation of Oklahoma (the “Pawnee Nation”) in federal court, involves claims against the United States Bureau of Indian Affairs, the Bureau of Land Management, and Sally Jewell as Secretary of the Interior.  Specifically, the complaint alleges that defendants’ approval of various oil and gas leases and drilling permits on Pawnee land failed to comply with several federal laws, including the National Environmental Policy Act (“NEPA”), the National Historic Preservation Act, and the American Indian Agricultural Resource Management Act of 1993. The complaint links these failures to various impacts on Pawnee land that have occurred as a result of oil and gas development, including earthquakes allegedly caused by hydraulic fracturing operations.  Like the petition in Eagle Road discussed above, the Pawnee Nation’s complaint makes specific reference to the magnitude 5.8 earthquake that occurred on September 3.  Among the myriad of violations alleged in the complaint is a claim that environmental assessments prepared to comply with NEPA in association with the issuance of drilling permits were deficient for failing to consider earthquakes as an “indirect impact.”  The complaint asks the court to set aside 17 leases approved in 2013, as well as at least 10 related permits to drill and associated sundry notices, and to enjoin the defendants from approving any other activities on the relevant leases until defendants have complied with all federal laws.  Read the complaint in Pawnee Nation of Oklahoma et al. v. Jewell et al., case number 4:16cv00697, in the U.S. District Court for the Northern District of Oklahoma here.

  • New Study Links Hydraulic Fracturing Operations to Earthquakes in Western Canada
    November 21, 2016

    A newly-released study links hydraulic fracturing operations to injection-induced earthquakes in Western Canada. Geoscientists at the University of Calgary studied all wells completed from December 2014 to March 2015 within the Devonian Duvernay Formation, finding both spatial and temporal correlations between hydraulic fracturing operations and seismic activity in the area. The largest observed seismic event during this time measured magnitude 3.9. Nonetheless, a prior study found that induced seismic events of magnitude 3 or greater are associated with only about 0.3% of hydraulically fractured wells in western Canada.

    The new study also found important differences in how different portions of the underlying fault system responded seismically; the east fault strand was primarily active during hydraulic fracturing operations, whereas the west fault strand remained activated for several months afterwards. The authors conclude that “the elastic response of the rockmass to hydraulic fracturing” is one of several different mechanisms that can trigger fault activation, leading to seismic activity. Indeed, the study acknowledges that the recent increase in induced seismic activity in North America “is primarily associated with” a different mechanism—the “high-rate injection of large volumes of saltwater into porous rock formations” that occurs in underground wastewater disposal operations. However, the authors also cite to two earlier studies that found links between hydraulic fracturing operations and earthquakes in Oklahoma and Poland, Ohio. Speaking with the New York Times, one of the study’s authors acknowledged that different geographic areas respond differently to hydraulic fracturing activity, and that additional research should be conducted to “understand[] the origin of the differences.” Read the study in full here.

  • Wyoming DEQ Issues Final Report Concluding that Upward Migration of Fracturing Fluids at Depth Is Unlikely
    November 11, 2016

    The Wyoming Department of Environmental Quality (“WDEQ”) has released its final report in response to resident concerns alleging a link between well water taste and odor issues in the Pavillion Gas Field and hydraulic fracturing activity. The final report brings to a close an investigative effort that initially began in 2009.  While a 2011 draft report by the United States Environmental Protection Agency (“EPA”) concluded that hydraulic fracturing fluids may have impacted groundwater in the Pavillion Gas Field, WDEQ’s final report concludes that “[i]t is unlikely that hydraulic fracturing fluids (injected into the deeper production zone(s)) have risen to the depths utilized by water-supply wells.”  This finding is consistent with WDEQ’s December 2015 draft final report as well as EPA’s June 2015 draft hydraulic fracturing study, which did not identify any instances where fluids migrated from the factures made in rock formations more than a mile below the surface up into aquifers that could be potential sources of drinking water. Like other recent studies, the final report further concludes that well construction issues present the “most probable pathway for gas or other fluids to reach shallow depths” via seepage along the wellbore, a risk WDEQ likewise identified in its December 2015 draft final report. Read WDEQ’s final report in full here and the tables here.

  • Industry Advocates Sue Over Pennsylvania’s New Hydraulic Fracturing Rules
    October 14, 2016

    On Thursday, October 13th, a trade group representing unconventional gas producers filed suit asking a Pennsylvania court to delay implementation of the rules until the appeal is decided. The challenge targets provisions in the new rules that industry representatives claim are vague, burdensome, and not authorized under Pennsylvania law, including a rule expanding operators’ responsibility to avoid and protect endangered species and rules governing site remediation, spill-reporting, and waste disposal, among others. The new rules have been in effect less than a week.