CHAPTER 5 RECOGNIZING CLIMATE CHANGE PERMITTING TRIGGERS
| Jurisdiction | United States |
(Jan 2015)
RECOGNIZING CLIMATE CHANGE PERMITTING TRIGGERS
Attorney
Holland and Hart LLP
Salt Lake City, Utah
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EMILY C. SCHILLING is an attorney with Holland and Hart LLP in Salt Lake City, Utah. Ms. Schilling's practice focuses on air quality matters, including federal rule development and related litigation, permitting, and compliance. She has more than a decade of environmental law experience, focusing on Clean Air Act matters, from permitting requirements for both criteria pollutants and greenhouse gases (GHGs) to compliance with standards for hazardous air pollutants. Ms. Schilling has extensive experience with the development of comments in federal rulemakings under the Clean Air Act, from GHG permitting, MACT standards, and National Ambient Air Quality Standards to EPA actions on regional haze. She also represents clients in litigation on a wide range of air quality matters, including challenges to EPA rulemakings in the D.C. Circuit. She is a graduate of Duke University School of Law (J.D., 2003) cum laude, where she served as Editor of the Alaska Law Review; Duke University, Terry Sanford Institute of Public Policy (Master of Public Policy, 2003); and Bowdoin College (B.A., 1997) magna cum laude, where she served as Editor in Chief of the Bowdoin Orient.
I. Introduction
Over the last five years, methane has become an increasingly important focus of the Obama Administration's efforts to address greenhouse gas emissions and global climate change. Indeed, of the six greenhouse gases ("GHG")2 subject to Environmental Protection Agency's ("EPA") 2009 endangerment finding, EPA characterized methane as one of "the two most important directly emitted, long-lived greenhouses gases," noting that "[t]he global atmospheric concentration of methane has increased by 149 percent since pre-industrial levels" based "primarily on anthropogenic emissions."3 In 2013, President Obama highlighted reductions in methane emissions as "critical" to addressing global climate change4 and in 2014, the President issued a multi-sectoral approach to reducing methane emissions.5 Two of the sectors highlighted in the President's Methane Strategy--the oil and gas and the mining industries--are critical
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economic drivers in the Mountain West. With this new federal focus on methane come regulatory and related permitting requirements that comprise an important part of planning and strategy for energy companies. Indeed, in December of 2014, EPA plans to release a strategy designed to "pursue further methane reductions" from the oil and gas sector,6 and the Bureau of Land Management is poised to consider regulation of venting and flaring of methane on federal lands. This paper addresses the development of data on which federal agencies are basing these GHG rulemakings, as well as federal permitting triggers for oil and gas and mining operations on both private and federal land.
II. The Implications of EPA's Greenhouse Gas Reporting Rule on Regulation of GHG, Particularly Methane, from Oil and Gas and Mining Operations
EPA's 2009 mandatory greenhouse gas reporting rule ("GHG Reporting Rule") has played a critical role in driving GHG regulation, particularly the regulation of methane. The rule requires monitoring and/or estimation and reporting of emissions of GHG--including methane--from a broad range of industrial sources. For example, soda ash producers began reporting GHG emissions in 2010 (Subpart CC) and EPA expanded the rule that same year to cover underground coal mines (Subpart FF) and petroleum and natural gas systems (Subpart W), which began reporting in 2011.7 Starting in 2014, EPA required industry reporters to use a new "global warming potential" value of 25 (as opposed to 21) for methane when estimating emissions, which results in higher total CO2 equivalent emissions from these source.8 The data gathered pursuant to the GHG Reporting Rule form the underpinning of EPA's GHG rulemakings, including the Administration's pending methane strategy.
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EPA promulgated the GHG Reporting Rule pursuant to its general authority under section 114 of the Clean Air Act, which authorizes EPA to require sources who own or operate emission sources to install monitoring, keep records, and report on emissions on a "one-time, periodic or continuous basis."9 The Rule requires estimation and reporting not just of combustion emissions from on-site boilers and other equipment, but CO2 emissions from process lines. For example, Subpart FF, which covers 4 facilities in southwestern Wyoming, requires annual reporting from soda ash process lines that liberate GHG (including methane) from the ore.10 Subpart FF covers a total of 118 underground mines, and requires Subpart W required upstream producers, natural gas distributors, and owners of pipeline transport systems that emit in excess of 25,000 metirc tons of carbon dioxide equivalent (CO2e) to report annually beginning in 2012 (for emissions in 2011).11 For the first time, upstream producers were required to estimate and report GHG emissions from venting related to well testing, well completions and workovers, storage tanks, pneumatic devices, and dehydration units.12 In November of 2014, EPA proposed amendments to Subpart W that would add to the list of covered facilities gathering and boosting facilities, completions and workovers of oil wells with hydraulic fracturing, and blowdowns of natural gas transmission pipelines between compressor stations.13
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In addition, EPA is proposing to require inclusion of well identification numbers for covered oil and gas wells.14
Recent emissions data reflects important trends in emissions of CO2 and methane. CO2e emissions from soda ash manufacturing, for example, totaled only 5.3 million metric tons (MMT) in 2013, a fraction of overall reported emissions, while natural gas and petroleum systems emitted a total 224.1 MMT of CO2e with methane emissions accounting for 75 MMT of total CO2e emissions.15 Fugitive emissions from coal mines totaled 41.5 MMT of CO2e in 2013.16
Together, oil and gas and coal mining emissions account for nearly 40% of total U.S. methane emissions.17 Overall emissions of methane, however, were 11% lower in 2012 than in 1990.18 Consistent with an overall trend of declining methane emissions, the emissions from coal mining and natural gas and petroleum system are substantially lower today than in 1990.19 Fugitive emissions from coal mines, specifically venting and degasification systems, declined 31 percent since 1990.20 Methane emissions from petroleum and natural gas systems have decreased 11% since 1990, even as methane-producing activities have increased rapidly.21
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Between 2011 and 2013, for example, 251 more petroleum and natural gas facilities filed reports under EPA's Greenhouse Gas Reporting Rule, but methane emissions dropped from 84.1 million metric tons of CO2e to 74 MMT, a reduction of 12%.22
The data gathered pursuant to the GHG Reporting Rule will continue to create a foundation for EPA's methane strategy and related rulemakings. President Obama's Methane Strategy relies in large part on emissions reported under this program, including its prioritization of methane emissions from coal mines and the oil and gas sector.23 Indeed, the Methane Strategy indicates that EPA will "continue to use the data collected through the GHGRP [GHG Reporting Rule] to improve the GHGI [GHG Inventory], particularly for the petroleum, natural gas, coal mining, and landfill sectors."24
III. Regulatory Triggers for GHG Under the Clean Air Act
EPA relies primarily on two provisions of the Clean Air Act to regulate emissions of methane: the Prevention of Significant Deterioration ("PSD") permitting provisions found in section 165 of the Act,25 and section 111's new and existing source performance standards.26 The Supreme Court recently circumscribed EPA's authority to regulate GHG under section 165 in Utility Air Regulatory Group v. EPA,27 and to date, EPA has not exercised its authority under section 111 to directly regulate methane emissions from either oil and gas or mining operations.
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Although not yet issued when this paper was submitted, EPA's pending methane strategy may change section 111 permitting triggers for the oil and gas industry.
A. Permitting GHG Under the Prevention of Significant Deterioration Program
The Supreme Court's decision in UARG v. EPA in changed the permitting landscape for numerous mining and oil and gas operations that vent primarily methane, which have operated in an uncomfortable limbo over the last four years. The UARG v. EPA decision effectively insulates operations that do not emit criteria pollutants at PSD and Title V permitting thresholds from permitting their greenhouse gases emissions--regardless of how significant those GHG emissions may be.28
In light of UARG v. EPA, how are a source's GHG emissions treated if emissions of any one criteria pollutant exceeds the major source threshold? EPA has not formally adopted a significance threshold for GHG as directed by the Supreme Court in UARG, but the Agency has stated in guidance that it intends to continue to apply the 75,000 ton-per-year permitting threshold for GHG to PSD permits.29 In other words, if a source has triggered PSD thresholds for a criteria pollutant, a source must also calculate its GHG emissions to determine whether they exceed 75,000 TPY of CO2e. For mining and oil and gas operations, this inquiry will necessarily include an assessment of fugitive emissions of GHG. If point and fugitive emissions exceed the threshold, then GHG are included in all subsequent assessments--including BACT determinations.
1. The role of fugitive GHG emissions in permitting
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Fugitive emissions are defined by federal PSD and Title...
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