Increasing Federal Regulation: NY Shale Development - Part 2
In New York, hydraulic fracturing - the technology used to develop natural gas resources from deep shale formations - will be regulated primarily at the state level. However, some federal regulation of hydraulic fracturing already exists and will likely expand due to significant public interest in shale development and push back regarding the “Halliburton loophole.” Recent federal agency regulations that will affect hydraulic fracturing operations in New York, as well as elsewhere, include: the United States Environmental Protection Agency’s (“EPA”) regulation of air impacts pursuant to the Clean Air Act (“CAA”); EPA’s study of the potential impacts to water resources from hydraulic fracturing; the Bureau of Land Management’s (“BLM”) proposed regulations for public and Indian lands; and the Federal Energy Regulatory Commission’s (“FERC”) decisions and policies regarding coordination between applicants and state agencies during its approval process for pipeline projects.
EPA’s First Federal Air Standards
On January 14, 2009, Wild Earth Guardians and San Juan Citizens filed a lawsuit against EPA in the United States Court of Appeals for the District of Columbia for failure to review and revise the New Source Performance Standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) for Oil and Natural Gas production source categories. On February 5, 2010, the court entered a Consent Decree where EPA agreed to review and revise those standards. The final rules, which include the first federal air standards for natural gas wells that are hydraulically fractured, were issued on April 17, 2012 and published in the Federal Register on August 15, 2012.
The CAA requires EPA to set NSPS for industrial categories that cause or significantly contribute to air pollution that may endanger public health or welfare, and, to review the standards every eight years. NSPS requirements are applicable to new and modified sources of air emissions. The previous NSPS for volatile organic compounds (“VOC”) from the Oil and Natural Gas production source category were issued in 1985. The CAA also requires EPA to establish NESHAP requirements, which are applicable to all major sources of hazardous air pollutants (“HAPs”), defined as a source that emits 10 tons or more per year of one HAP or 25 tons or more of combined HAPs. The previous NESHAP was issued in 1999.
According to EPA, the largest emissions of VOCs occur as wells that have been fractured are completed in preparation for production. During “flowback,” which typically lasts 3-10 days, fracturing fluids, water and reservoir gas, including methane, VOCs and other HAPs, come to the surface. Under the new NSPS, operators of hydraulically fractured and re-fractured wells must notify EPA via email no later than two days before completion work on a well begins.
To reduce emissions of VOCs associated with flowback, EPA established a phased approach. In Phase 1, which is currently in effect, VOC emissions that would otherwise escape must be flared, or the gas must be captured using “green completion” technology. In Phase 2, which begins January 1, 2015, well operators will no longer have the option of flaring and will be required to utilize green completions, and make recovered gas available for use or sale. EPA states that green completions will reduce VOC emissions from hydraulically fractured wells by 95%, and while neither methane nor NOx will be regulated, according to EPA, green completions will have the co-benefit of reducing emissions of these pollutants. New exploratory, delineation and low-pressure wells will not be subject to these NSPS green completion requirements.
As an incentive to use green completion earlier than required under the NSPS, wells that are re-fractured to stimulate production or to obtain gas from a different zone, will not be considered “modified” if green completion rather than flaring is used during flowback. In some states, this will allow operators to re-fracture wells without triggering additional air permitting. Notably, reduced emission completions have been proposed in New York’s draft supplemental generic environmental impact statement (“SGEIS”).
In addition to well completion, the NSPS contain requirements for pneumatic controllers, which are used to maintain liquid level, pressure and temperature, and requirements for storage tanks. Under the NSPS, by October 15, 2013, each pneumatic controller must be limited to a gas bleed rate of 6 ft3/hour and storage tanks at well sites with VOC emissions of 6 tons/year or greater must reduce VOC emissions by 95%, which EPA anticipates will be accomplished by the use of combustion devices. Certified annual reports on well completions, and information on compressors, pneumatic controllers and storage tanks located at the well sites, are required to be submitted under the NSPS.
The NESHAP contains requirements for storage tanks and glycol dehydrators located at well sites. In determining whether a facility is a major source subject to the NESHAP requirements, emissions from all storage vessels must now be included. The new NESHAP retains the existing standards for large glycol dehydrators, which requires emissions of HAPs to be reduced by 95% or benzene emissions reduced to less than one ton/year, and adds new requirements for small dehydrators, which are dehydrators with an average natural gas throughput of 85,000 meters3/day or annual benzene emissions of less than one ton/year.
Small dehydrators must meet a unit-specific emission limit for HAPs emissions that is based on gas throughput and composition. New small dehydrators must comply immediately upon startup, and existing small dehydrators, those whose construction began before August 23, 2011, must comply by October 15, 2015.
Challenges to EPA’s Rules
On October 15, 2012, both industry groups and environmentalists challenged the NSPS and the NESHAP in court. In addition, on December 11, 2012, seven states, including New York, provided EPA with a 60-day notice of intent (“NOI”) to sue for failure to adopt NSPS for methane emissions from the oil and natural gas industry.
The main industry challenges are based on the green completion requirements and the one year period to comply with certain requirements. The main environmentalists’ challenges are based on the phased approach for green completion requirements, the adequacy of the NESHAP risk assessment and that methane emissions are not regulated.
The states’ NOI asserts that, in light of the EPA 2010 greenhouse gas endangerment finding, EPA’s failure to determine whether to adopt NSPS for methane emissions from new oil and gas sources failed to satisfy its duty under section 111(b) of the CAA. EPA stated in its Federal Register notice that it will “continue to evaluate the appropriateness of regulating methane with an eye toward taking additional steps if appropriate.” While the threatened lawsuit seeks to require EPA to determine whether to regulate methane from the oil and gas industry, the states affirmatively assert that there is plenty of evidence to support EPA’s regulation of methane because oil and gas operations are the largest source of methane emissions in the U.S. and account for 5% of carbon dioxide equivalent emissions. The states further note that while the NSPS and NESHAP will have the incidental effect of controlling some methane emissions, the vast majority of methane emissions will be uncontrolled. The states assert that there are readily available methods to reduce methane emissions and that controls are cost-effective or even profitable, because the methane could be recovered and sold.
Air Permitting Aggregation
On August 7, 2012, the United States Court of Appeals for the Sixth Circuit struck down EPA’s interpretation of when sources are to be aggregated for purposes of Title V and New Source Review permitting in Summit Petroleum Corp. v. EPA. Under 40 C.F.R § 71.2, multiple pollutant emitting sources can be aggregated and considered a single source for purposes of Title V and New Source Review permitting if they: (1) are under common control; (2) are located on one or more contiguous or adjacent properties; and (3) belong to the same industrial grouping. EPA interprets “adjacent” not to include a dispositive distance requirement, and that other factors, such as “nature of the relationship between the facilities” and the “degree of interdependence” are the relevant inquiries. The court rejected EPA’s interpretation and held that “adjacent” was not ambiguous, and that adjacency is purely physical and geographical. The court then declined to apply any deference to EPA’s interpretation of “adjacent”, because it defies the regulation’s plain meaning, and noted that virtually every oil and gas facility is connected by a pipeline and that aggregating these activities without regard to their physical proximity is inherently unreasonable under EPA’s regulations.
On December 21, 2012, EPA issued a memorandum responding to the Summit decision. While EPA will no longer consider interrelatedness in determining adjacency when making source determination decisions in the Sixth Circuit (Michigan, Ohio, Tennessee, and Kentucky), it will make no change in other jurisdictions to its practice of determining adjacency based on the functional interrelatedness of facilities. A bright line physical proximity approach, as opposed to the interrelatedness analysis, is gaining favor in Pennsylvania. Recognizing that interconnected pipelines create a unique factor in the aggregation analysis, the Pennsylvania Department of Environmental Protection issued a policy in October 2012 that establishes a physical distance of one quarter mile between facilities as a qualifying criteria for determining whether sources should be aggregated. The current proposal in New York’s SGEIS) is similar to the EPA approach rejected by the Sixth Circuit, as it relies on functional interrelatedness and not physical proximity alone. However, as New York’s draft pre-dates the Summit decision, it is unclear if New York will modify its proposed aggregation test in the final SGEIS.
Potential Future Regulation
EPA, at the request of Congress, is completing a national study evaluating the potential impacts of hydraulic fracturing on drinking water resources. A progress report outlining the framework of the overall study was released on December 21, 2012. The final report will include the results of studies related to: water acquisition; chemical mixing; well injection; flowback; produced water; wastewater treatment; and waste disposal. A draft of the report is scheduled to be issued in late 2014.
In May 2012, BLM proposed new regulations for hydraulic fracturing on federal and Indian-owned lands. The proposed regulations include requirements for public disclosure of chemicals used in hydraulic fracturing activities, guidelines for encasing wells and requirements for water management plans. Based on opposition to the proposed rules, the Department of the Interior stated on January 18, 2013 that it would be issuing new proposed rules for comment during the first quarter of 2013.
The approval of natural gas pipelines by FERC, including pipelines currently proposed for New York, has become a national front in the battle over shale gas development. Drilling opponents oppose projects in FERC proceedings for pipelines and compressor stations that have a connection with the transport of shale gas, even when the gas is produced in other states. Many of the concerns raised reflect typical development issues involving water resources and wetlands, vegetation, wildlife, aesthetics, air quality, and socioeconomic impacts, as well as “not in my backyard” sentiments that often accompany large projects. FERC has generally found that these potential impacts will be avoided or mitigated through project design and the implementation of special conditions required by the Environmental Assessment.
Drilling opponents also argue that cumulative impacts from other shale production, and the use of natural gas, should be included in FERC’s environmental review of these projects. FERC, however, has limited its cumulative impacts review to shale production within the proximity of proposed projects, finding that both distant gas wells and end use impacts fall outside of the scope of its environmental review. FERC has stated that potential impacts from the end use of the gas are not reasonably foreseeable, as the quantity of gas that will be transported at a given time and the end user are uncertain. Moreover, according to FERC, emissions from combustion are already addressed by the CAA and state and local regulations.
In addition to opponent challenges to projects at the federal level, FERC’s policy concerning the coordination between applicants and state environmental agencies may result in applicants being subject to legal challenges and delays at the state level. States are generally preempted from requiring applicants to obtain environmental permits for projects subject to FERC approval under the Natural Gas Act (“NGA”), except for federally-delegated permits (i.e. Section 401 water quality certification and Title V permits). In National Fuel Gas Corp. v. Public Service Com., decided in 1989, the Second Circuit Court of Appeals held that New York could “not engage in concurrent site-specific environmental review,” which the court stated would impose costs and delays that would undermine FERC’s approval process that already includes an environmental review. FERC too, in the 1992 Iroquois Gas case, asserted its jurisdiction with a warning that FERC’s policy of encouraging cooperation between states and applicants “does not mean that those agencies may undermine. . . the force and effect of a certificate issued by this Commission.”
FERC’s 2003 guidance for wetland and waterbody construction and mitigation procedures, which is currently under revision, sends mixed signals regarding the degree of cooperation required between applicants and states. With regard to waterbody crossings, the guidance states that applicants should: “Apply for state-issued water body crossing permits and obtain individual or generic section 401 water quality certification or waiver.” (emphasis added). Although this language seems to require only an application, rather than granting states authority to issue state-based permits, it creates ambiguity for applicants, who, as a matter of FERC practice, are encouraged not to assert federal preemption in the early stages of a project. However, FERC’s more recent 2007 guidance on coordination with states does not mention state based permits and fails to clarify the requirements associated with state authorizations. Rather, it only refers to “federal authorizations,” which includes a “State administrative agency or officer acting under delegated Federal authority.” (emphasis added).
As a result of this uncertainty, applicants must attempt to determine for themselves the dividing line between FERC-endorsed cooperation with state agencies and ceding jurisdiction to a state-based approval process. An applicant entangled in a state approval process could have its entire project timeline jeopardized by an agency decision to hold a public hearing, or by legal challenges that arise out of the state process. Applicants that argue preemption at this later stage may risk the appearance of attempting to avoid compliance and potentially tarnishing relationships with state agencies and the public. With increased public attention on shale development, and to avoid state level procedures that could cause delays and increased costs for a FERC project, applicants should carefully consider their options when interacting with state agencies such as the New York State Department of Environmental Conservation.
As the development of shale gas, and the public interest in shale gas development, continues to grow in New York and elsewhere, federal involvement will also likely continue to grow. There are a number of outstanding federal issues, including: whether the EPA regulations will withstand the various challenges, how the Sixth Circuit decision will affect air permitting, what new federal regulations will emerge and how FERC will handle the interaction between states and applicants, that are likely to culminate in the months, and years, ahead.
Hiscock & Barclay has first-hand experience in New York's ongoing regulatory review of shale development and has been involved in the process since the very beginning. Please contact Frank V. Bifera, Chair of the Firm's Environmental Practice Area at (518) 429-4224 or firstname.lastname@example.org, or Yvonne E. Hennessey at (518) 429-4293 or email@example.com for more information.