There's Something in the Air: New and Evolving - Bryan Cave LLP

6-1

Chapter 6THERE’S SOMETHING IN THE AIR:

NEW AND EVOLVING AIR QUALITY REGULATIONS IMPACTING OIL AND GAS DEVELOPMENT

Colin G. HarrisBryan Cave HRO

Boulder, Colorado

Ivan L. LondonBryan Cave HRO

Denver, Colorado

Synopsis

§ 6.01 Introduction§ 6.02 Framework of the Clean Air Act

[1] National Ambient Air Quality Standards[2] State Implementation Plans[3] Permits

[a] Types of Permits[i] Preconstruction New Source Review

Permits for Major Sources[ii] Minor Sources[iii] General Permits and Permits by Rule[iv] Operating Permits

[4] Requirements for New and Modified Sources[5] Standards for Hazardous Air Pollutants for New

and Existing Sources[6] State Primacy[7] Other Sources of Air Quality Control: Federal

Agencies, Oil and Gas Commissions, and Local Governments

This paper was originally published by the Rocky Mountain Mineral Law Foundation in the Proceedings of the 58th Annual Rocky Mountain Mineral Law Institute (2012)

6-2 Mineral Law Institute

§ 6.03 Emission Sources and Control Technologies Affecting Oil and Gas Operations[1] Drilling and Completions[2] Flaring[3] Tanks[4] Processing and Dehydration[5] Compression[6] Equipment Leaks

§ 6.04 New and Revised Standards for Oil and Gas Operations[1] NSPS OOOO

[a] Hydraulic Fracturing for Gas Wells[b] Oil Wells[c] Compressors[d] Pneumatic Controllers[e] Storage Vessels

[2] NSPS KKK[3] NSPS LLL[4] NESHAP HH[5] RICE Subject to NSPS and NESHAP

[a] NSPS IIII[b] NSPS JJJJ[c] NESHAP ZZZZ

§ 6.05 Air Quality Standards: Ozone Nonattainment[1] Background[2] The Practical Impacts of Nonattainment[3] Ozone Nonattainment Areas in the Intermountain

West Associated with Oil and Gas Development[a] Denver Northern Front Range[b] Jonah/Pinedale, Wyoming[c] Uintah Basin, Utah

[4] Ozone Advance Program§ 6.06 Aggregation of Oil and Gas Operations

Air Quality Regulations 6-3

[1] Frederick Compressor Station—Contiguous or Adjacent

[2] Florida River Compression Facility—Contiguous or Adjacent

[3] Sims Mesa CDP—Common Control[4] Other Aggregation Cases

[a] Midwest—Contiguous or Adjacent[b] Marcellus Shale

[5] Aggregation Lessons§ 6.07 EPA’s Indian Country Rules

[1] The “Gap” in Indian Country Permitting[a] Indian Country Minor Source Program[b] Indian Country Nonattainment NSR Program

[2] Key Time Frames[3] Implementation: Permitting, Public Comment,

and Review[4] Fort Berthold Indian Reservation

§ 6.08 Greenhouse Gas Regulation[1] Tailoring Rule[2] Greenhouse Gas BACT for Oil and Gas[3] Mandatory Reporting Rule

§ 6.09 Land Management Decisions and the National Environmental Policy Act[1] Air Quality Mitigation in NEPA Documents[2] Formalizing Air Quality Review and Data[3] NEPA Case Study: Hell’s Gulch, White River

National Forest, Colorado§ 6.10 Modeling

[1] Permitting[2] One-Hour NO2 and SO2 NAAQS[3] Controversies

§ 6.11 Startup, Shutdown, and Malfunction Exemption[1] Elimination of the Exemption

6-4 Mineral Law Institute § 6.01

[2] SSM in Permitting§ 6.12 Enforcement§ 6.13 Local Regulation

[1] Shifting Focus[2] Scientific Controversies[3] Local Control[4] Preemption Litigation

§ 6.14 Conclusion: Overcoming Regulatory Strategies That Threaten Development

§ 6.01 Introduction*

“Call out the instigators Because there’s something in the air We’ve got to get together sooner or later Because the revolution’s here . . . .”

— Thunderclap Newman, “Something in the Air,” on Hollywood Dream (Track Records 1970).

“Something in the Air” was a number-one single by the band Thunder-clap Newman in 1969.1 The song was a generic and dreamy call for revolu-tion as the Sixties drew to a close. Today, the lyrics could symbolize one the most significant challenges facing oil and gas development: regulators and activist groups increasingly perceive oil and gas extraction and midstream activities as significant contributors to the presence of “something in the air,” and “revolution” may aptly characterize the fast-paced and compre-hensive air quality regulatory changes, both new and evolving, that regula-tors are directing at the oil and gas industry to address these concerns.

The Clean Air Act (CAA)2 may be the most complex, burdensome, and costly environmental statute ever promulgated. By any measure, the pain has resulted in considerable gain: the CAA has a proven track record of

* Cite as Colin G. Harris & Ivan L. London, “There’s Something in the Air: New and Evolving Air Quality Regulations Impacting Oil and Gas Development,” 58 Rocky Mt. Min. L. Inst. 6-1 (2012).

1 Pete Townshend of The Who created Thunderclap Newman for The Who’s roadie John “Speedy” Keen, who wrote and sang “Something in the Air.” Townshend played bass on the song using the pseudonym Bijou Drains. Townshend used this pseudonym again on the song “Misunderstood” from his excellent 1977 album Rough Mix recorded with Ronnie Lane of Faces.

2 42 U.S.C. §§ 7401–7671q.

§ 6.01 Air Quality Regulations 6-5

reducing air pollutants. When Thunderclap Newman released “Something in the Air” in 1969, urban smog episodes were a major public health crisis, lead from vehicles presented chronic health risks, and pollution control technology was in its infancy. Since then, emissions of the most common air pollutants have declined by 41%, while gross domestic product has increased by more than 64%.3 The CAA started a march of emission con-trol technology that continues to this day.

CAA regulators are not resting on their laurels. Congress has amended the law several times, and the implementing regulations at the federal and state level continue to grow and multiply like the many-headed Hydra. Regardless of whether one believes that this is regulatory overreaching or simply a natural response to new air quality challenges, the CAA remains a very powerful tool to affect how industry conducts business. In fact, a strong argument could be made that, unlike the Clean Water Act (CWA)4 and hazardous waste laws, which have reached a high degree of maturity and certainty, the CAA remains in considerable flux and will grow more stringent and complex, at a very deliberate pace and in the public eye, to address concerns that air quality priorities have lagged behind other envi-ronmental laws and regulations.

This scenario poses special issues for the upstream and midstream oil and gas industry, which includes exploration, drilling, completions, sepa-ration, gathering, processing, and compression. Over the past several years, oil and gas production and related midstream activities in the Intermoun-tain West have increased due to spectacular discoveries in unconventional resource plays, such as shale gas, and new technologies, such as horizon-tal drilling and hydraulic fracturing.5 Although natural gas prices have declined due to oversupply and other factors, resulting in lower natural gas rig counts,6 the industry has offset the decline by increasing the number of rigs targeting crude oil in response to high crude oil prices.7 Addition-ally, the industry has held natural gas production steady in areas where

3 EPA, “40th Anniversary of the Clean Air Act,” http://www.epa.gov/oar/caa/40th.html.4 33 U.S.C. §§ 1251–1387.5 See generally Energy Info. Admin., “Review of Emerging Resources: U.S. Shale Gas and

Shale Oil Plays” (July 2011); EPA, “An Assessment of the Environmental Implications of Oil and Gas Production: A Regional Case Study” (Working Draft Sept. 2008) (Assessment of Environmental Implications).

6 Energy Info. Admin., “Short-Term Energy Outlook,” at 7 (May 2012) (Short-Term Energy Outlook) (citing Baker Hughes statistics).

7 See id. at 5–6; see also Energy Info. Admin., “U.S. Oil Rig Count Overtakes Natural Gas Rig Count” (May 9, 2011), http://www.eia.gov/todayinenergy/ (search “Archive” for May 2011).


operators can supplement natural gas revenues with the sale of natural gas liquids (NGL), which they process from liquids-rich natural gas and sell at prices that approximate crude oil prices.8 Oil and gas development will likely continue to grow and intensify.

The pace of this activity is facing gale-force headwinds caused by air quality regulation and disputes. The U.S. Environmental Protection Agency (EPA) and state and local agencies already have an intimidating array of rules applicable to drilling, natural gas processing, storage, compression, dehydration, and pipeline transportation.9 The scope and stringency of regulations is growing.10 Also, federal land management agencies increas-ingly impose extra-regulatory air quality mitigation measures through the National Environmental Policy Act of 1969 (NEPA).11 Even when air qual-ity is addressed, project opponents routinely challenge NEPA decisions based on allegedly deficient review of air issues. Further, citizen groups routinely challenge air permits based on complex and increasingly novel technical and legal arguments, resulting in delay. Amid this regulatory and legal activity, enforcement is escalating. Accordingly, oil and gas operators face increased costs, regulatory burdens, public scrutiny, and delay. High profile issues may even result in complete barriers to development.

We will see whether we are experiencing a manageable evolution of the regulatory framework, or if “the revolution’s here,” bringing with it a fun-damental restructuring of the way industry will need to approach every oil and gas development project. One thing is certain: air quality has become the primary lightning rod for environmental regulatory action and stake-holder disputes regarding oil and gas development in the Intermountain West. Section 6.02 of this chapter presents the legal framework of the CAA so that operators can analyze the impacts of regulatory developments on oil and gas development in legal context. Section 6.03 explains the air quality-related emissions sources and control technologies involved in oil and gas activities. Then, sections 6.04 through 6.13 address specific recent

8 See Short-Term Energy Outlook, supra note 6, at 7.9 See, e.g., 40 C.F.R. §§ 63.760–.777 (regulating emissions of hazardous air pollutants

(HAP) from oil and gas production facilities); 5 Colo. Code Regs. § 1001-9:XII (Colorado regulations for volatile organic compound (VOC) emissions from oil and gas operations such as storage tanks).

10 See, e.g., 77 Fed. Reg. 49,490, 49,542 (Aug. 16, 2012) (to be codified at 40 C.F.R. §§ 60.5360–.5430 (effective Oct. 15, 2012)) (newly promulgated regulations limiting air emissions from natural gas well completions and other natural gas production and process-ing equipment).

11 42 U.S.C. §§ 4321–4347.

§ 6.02[1] Air Quality Regulations 6-7

regulatory developments affecting the industry, using examples to demon-strate practical impacts.

§ 6.02 Framework of the Clean Air Act[1] National Ambient Air Quality Standards

The CAA requires EPA to set “primary” and “secondary” national ambi-ent air quality standards (NAAQS) for any pollutant reasonably anticipated to endanger public health or welfare, and to classify areas of the United States based on whether they meet those standards.12 The resulting air quality standards apply to six “criteria pollutants”: carbon monoxide (CO), lead, nitrogen oxides (NOx),13 ozone, particulate matter pollution (PM, PM2.5, or PM10), and sulfur dioxide (SO2).14 The criteria pollutant of most concern to oil and gas operators is ozone and its precursors, nitrogen diox-ide (NO2) and volatile organic compounds (VOC).15 Oil and gas activities in heavily developed basins or populated regions likely contribute to ozone levels at, near, or exceeding the NAAQS.16

Once EPA establishes or revises an air quality standard, the CAA directs each state to propose designations for those regions that meet the standard, i.e., “attainment areas,” those that do not, i.e., “nonattainment areas,” and those that EPA cannot classify.17 If EPA designates an area non-attainment, then the state must develop a plan to bring the area back into attainment within a specified period. The applicable regulations impose strict emis-sion control and other measures on sources operating or proposing to build in nonattainment areas.18

12 42 U.S.C. §§ 7407, 7408(a)(1)(A), 7409; accord Clean Air Amendments of 1970, Pub. L. No. 91-604, 84 Stat. 1676, 1679–80 (1970). EPA must set “primary” NAAQS at a level req-uisite to protect the public health with an adequate margin of safety. 42 U.S.C. § 7409(b)(1).

13 EPA defines NOx to include “all forms of oxidized nitrogen compounds.” EPA, “Inte-grated Science Assessment for Oxides of Nitrogen—Health Criteria,” at ch. 1 (July 2008).

14 43 Fed. Reg. 46,246 (Oct. 5, 1978) (initial standards for lead); 36 Fed. Reg. 8186 (Apr. 30, 1971) (initial standards for CO, NO2, SO2, PM, and ozone); see also 77 Fed. Reg. 20,218 (Apr. 3, 2012) (revised secondary standards for NO2 and SO2); 76 Fed. Reg. 54,294 (Aug. 31, 2011) (recent review of CO); 75 Fed. Reg. 35,520 (June 22, 2010) (revised primary stan-dards for SO2); 75 Fed. Reg. 6474 (Feb. 9, 2010) (revised primary standards for NO2); 73 Fed. Reg. 66,964 (Nov. 12, 2008) (revised standards for lead); 73 Fed. Reg. 16,436 (Mar. 27, 2008) (current standards for ozone); 71 Fed. Reg. 61,144 (Oct. 17, 2006) (revised standards for PM).

15 Assessment of Environmental Implications, supra note 5, at 2-10.16 Id. See infra § 6.05.17 42 U.S.C. § 7407(d)(1).18 See generally id. §§ 7502, 7503; 40 C.F.R. §§ 51.165–.166 & pt. 51, app. S.

6-8 Mineral Law Institute § 6.02[2]

[2] State Implementation PlansUsually, states take the lead in ensuring that oil and gas activities do

not violate the NAAQS.19 The CAA requires states to submit state imple-mentation plans (SIP) explaining how they will implement, maintain, and enforce the NAAQS. State regulators base their implementation plans on emission inventories and computer models, which enable them to deter-mine whether pollution levels will exceed the air quality standards.20 SIPs consist of permit programs that may impose multiple types of permits at all stages of oil and gas development.21 State regulators issue permits to limit the amounts and types of emissions that each permit holder is allowed to discharge.22 In addition to permits, various rules limit emissions at specific types of oil and gas equipment or facilities. These include the “new source performance standards” for new and modified sources (NSPS),23 and the “national emission standards for hazardous air pollutants” (NESHAP).24

[3] PermitsEach SIP must also have legally enforceable procedures requiring cer-

tain sources to obtain construction permits.25 Very generally, permitting programs divide sources into larger emitting facilities, known as “major sources,”26 and facilities that emit less than “major” amounts, or “minor sources.”27 For example, the CAA requires a person who wants to construct

19 See North Carolina v. EPA, 531 F.3d 896, 902 (D.C. Cir. 2008); see also 42 U.S.C. § 7410.20 See 40 C.F.R. § 51.1 (“States must inventory emission sources located on nontribal

lands and report this information to EPA.”).21 42 U.S.C. §§ 7410, 7475, 7503, 7661a.22 United States v. Marine Shale Processors, 81 F.3d 1329, 1356 (5th Cir. 1996).23 42 U.S.C. § 7411; see infra § 6.02[4].24 42 U.S.C. § 7412; see infra § 6.02[5].25 40 C.F.R. § 51.160(a)(2).26 42 U.S.C. §§ 7475 (major emitting facility), 7503 (major stationary source), 7661a(2)

(major source). For the purposes of describing the programs cited in this chapter, the authors follow the example of the CAA, which uses these variations on “major source” interchangeably. See Nat’l Mining Ass’n v. EPA, 59 F.3d 1351, 1361 (D.C. Cir. 1995) (citing 42 U.S.C. §§ 7479, 7602(j)).

27 As will be discussed in § 6.06, infra, certain CAA permitting programs only apply to a “major source,” which is a subset of “stationary source.” The aggregation test for determin-ing whether separate facilities constitute one “stationary source” for the purposes of deter-mining whether they collectively comprise a “major source” has become a controversial aspect of oil and gas air quality regulation.


a major source of pollutants28 in an attainment or unclassifiable29 area to first obtain a preconstruction permit called a prevention of significant deterioration (PSD) permit.

A proposed new facility is subject to the PSD preconstruction permit-ting program if it emits or has the “potential to emit” levels of pollution above certain threshold amounts.30 “Potential to emit” (PTE), is one of the most important concepts in the CAA, and every operator must have a keen understanding of the legal and engineering aspects of PTE calculations.31 To determine if a facility has a PTE above a permitting threshold, the operator generally must assume worst-case operating conditions. In other words, PTE is the maximum amount of emissions that a facility could emit if it operated at 100% design capacity, 24 hours per day, 365 days per year. Most importantly, PTE calculations cannot take into consideration actual or, for a new or modified facility, proposed pollution control equipment. Obviously, this will overstate emissions in almost all cases, and may cause an operator to trigger burdensome “major source” permitting programs, like PSD, that would otherwise never apply based on actual emissions into the environment.

There is an exception to this seemingly harsh result if the pollution con-trols are or, upon startup, will be “federally enforceable.”32 This means that the source agrees to limit its emissions to certain levels based on operation

28 See 42 U.S.C. §§ 7475(a), 7479(1).29 For simplicity, this chapter will refer to “attainment or unclassifiable” areas collectively

as “attainment” areas unless otherwise noted.30 42 U.S.C. § 7479(1); 40 C.F.R. § 52.21(b)(4). The relevant portion of the statute states

that a stationary source can be a “major emitting facility” if it emits or has the potential to emit 250 tons per year (tpy) of any air pollutant. 42 U.S.C. § 7479(1).

31 Operators typically use emissions factors and calculation guidance documents pro-vided by EPA and the states to calculate PTE. E.g., N.D. Dep’t of Health, Div. of Air Quality, “Bakken Pool, Oil and Gas Production Facilities, Air Pollution Control Permitting & Com-pliance Guidance,” at 11-23, app. B (effective May 2, 2011) (Bakken Guidance).

32 PTE reflects a source’s maximum capacity to emit a pollutant under its physical and operational design taking into account any “federally enforceable” physical or operational limitations, such as air pollution control equipment and restrictions on hours of opera-tion. 40 C.F.R. § 52.21(b)(4). However, EPA defines “federally enforceable” essentially as “enforceable by EPA.” See id. § 52.21(b)(17). A federal court vacated and remanded “fed-erally enforceable” as applied to the CAA’s HAP program in 1995. Nat’l Mining Ass’n v. EPA, 59 F.3d 1351, 1362–65 (D.C. Cir. 1995). The court then did so again as applied to the CAA’s construction permit program. Chemical Mfrs. Ass’n v. EPA, Nos. 89-1514, 89-1515, 89-1516, 1995 WL 650098, at *1 (D.C. Cir. Sept. 15, 1995) (unreported); accord 67 Fed. Reg. 80,186, 80,191 (Dec. 31, 2002). However, EPA has not promulgated a new federal defini-tion of PTE. EPA has nevertheless continued to prosecute alleged CAA violations using

6-10 Mineral Law Institute § 6.02[3][a][i]

of control equipment or based on process restrictions. The vast majority of construction projects avoid “major” source permitting programs by creating such “enforceable” limits.33 Construction permits, known as “syn-thetic minor permits,” typically set forth the enforceable limits on PTE.34 A “synthetic minor source” contrasts with a “natural minor,” whose emis-sions would not exceed significance thresholds even when operating at full capacity without additional pollution control equipment.35 These “syn-thetic minor sources” could theoretically emit pollutants in “major source” amounts, but operate subject to limitations that result in actual emissions staying below the thresholds.36 Most state and local permitting programs provide for the issuance of synthetic minor source permits.37 This is not a loophole, but rather a recognition that limited major source permitting resources should focus on truly large facilities with actual emissions in excess of major source thresholds.

[a] Types of Permits[i] Preconstruction New Source Review

Permits for Major SourcesAs discussed above, SIPs must include permitting programs for the con-

struction and/or modification of stationary sources. EPA calls these con-struction permit programs “new source review” (NSR).38 For “major” NSR,

its vacated and remanded “federally enforceable” concept. See generally United States v. Questar Gas Mgmt. Co., No. 2:08-CV-167 TS, 2011 WL 1793164 (D. Utah May 11, 2011); United States v. Questar Gas Mgmt. Co., No. 2:08CV167DAK, 2010 WL 1417856 (D. Utah Mar. 29, 2010) (the authors were involved in the cited cases).

33 Memorandum from John S. Seitz, Dir., EPA Office of Air Quality Planning & Stan-dards, & Eric V. Schaeffer, Dir., EPA Office of Regulatory Enforcement, to Dir., Office of Ecosystem Prot., EPA Regions 1 et al. (Dec. 20, 1999); Memorandum from John S. Seitz, Dir., EPA Office of Air Quality Planning & Standards, & Robert I. Van Heuvelen, Dir., Office of Regulatory Enforcement, to Reg’l Offices, at 2-4 (Jan. 22, 1996); Memorandum from John S. Seitz, Dir., EPA Office of Air Quality Planning & Standards, and Robert I. Van Heuvelen, Dir., EPA Office of Regulatory Enforcement, to Dir., Air, Pesticides and Toxics Mgmt. Div., EPA Regions 1 and 4 et al. (Jan. 25, 1995); Memorandum from John Calcagni, Dir., EPA Air Quality Mgmt. Div., to William A. Spratlin, Dir., Air and Toxics Div., EPA Region 7, (Sept. 18, 1992); accord, e.g., Mont. Dep’t of Air Quality, Air Res. Mgmt. Bureau, Oil or Gas Well Facilities and Calculating Potential to Emit (PTE) (effective June 1, 2007).

34 See, e.g., Okla. Dep’t of Envtl. Quality, Air Quality Div., “Title V Oil & Gas Facilities Fact Sheet,” http://www.deq.state.ok.us/AQDnew/resources/factsheets/o&gfctst.html.

35 Memorandum from John S. Seitz, Dir., EPA Office of Air Quality Planning & Stan-dards, to EPA Reg’l Air Dirs. and Counsels, at 2 n.2 (Mar. 7, 1999).

36 76 Fed. Reg. 38,748, 38,769 (July 1, 2011).37 Id. at 38,750.38 E.g., 74 Fed. Reg. 51,418, 51,421 (Oct. 6, 2009).

§ 6.02[3][a][ii] Air Quality Regulations 6-11

which applies to the construction or modification of stationary sources that meet threshold emissions levels, the CAA sets forth the parameters for the permit programs in considerable detail.39 The CAA’s requirements for major NSR differ in turn depending on whether a region is designated “attainment” or “nonattainment.”40

If a proposed new source or modification to an existing facility located in an attainment area has a PTE in excess of the prescribed thresholds, and a synthetic minor permit is not available, then the operator must obtain a PSD preconstruction permit.41 EPA has created a complex, lengthy, and elaborate permitting process.42 The process requires the permit applicant to demonstrate that the proposed source will not have an unacceptable impact on air quality, and to control emissions of pollutants through appli-cation of the “best available control technology” (BACT).43 During review of PSD applications, permitting agencies measure whether a source will unacceptably impact air quality by analyzing compliance with the air qual-ity standards and any applicable air quality “increments,” i.e., the maximum allowable increases in a particular pollutant’s concentration that may occur above a baseline ambient air concentration for that pollutant.44 Similarly, if a proposed new source or modification to an existing facility located in a nonattainment area has a PTE in excess of the prescribed thresholds, and a synthetic minor permit is not available, then the operator must obtain a “Nonattainment NSR” preconstruction permit.45

[ii] Minor SourcesThe CAA prescribes only the barest of requirements for “minor” NSR.46

Accordingly, minor NSR programs vary from state to state.47 Oil and gas

39 42 U.S.C. §§ 7470–7503.40 Luminant Generation Co. v. EPA, 675 F.3d 917, 922 n.1 (5th Cir. 2012).41 42 U.S.C. § 7475(a).42 See 40 C.F.R. § 52.21(j)–(r).43 42 U.S.C. §§ 7475(a)(1), 7479(1), (3). Congress defined BACT. Id. § 7479(3).44 40 C.F.R. § 52.21(c). Congress established the maximum allowable increases and

concentrations for sulfur oxides and PM. 42 U.S.C. § 7473. For ozone, however, Congress charged EPA with promulgating increments. Id. § 7476(a), (c).

45 42 U.S.C. § 7502(c)(5). Congress created a Nonattainment NSR threshold of 100 tpy for any pollutant rather than the 250-tpy emission threshold for PSD permits. Id. § 7602(j). EPA has also promulgated extensive and complex implementing regulations for the Non-attainment NSR program. See 40 C.F.R. §§ 51.165–.166 & pt. 51, app. S.

46 42 U.S.C. § 7410(a)(2)(C). EPA has promulgated a similarly sparse set of implementing regulations for minor NSR. See 40 C.F.R. §§ 51.160–.166.

47 74 Fed. Reg. 51,418, 51,421 (Oct. 6, 2009).

6-12 Mineral Law Institute § 6.02[3][a][iii]

operations frequently use minor source preconstruction permits because, except for oil refining and natural gas processing, operators tend to use many small facilities and minor installations rather than a few large facilities.

[iii] General Permits and Permits by RuleMany permitting agencies also provide “general permits” and “permits

by rule” for various oil and gas operations. A “general permit” is a precon-struction permit that operators can use for a number of similar emissions units or minor sources.48 A “permit by rule” is a regulation that operators can use to exempt an air emissions source from otherwise applicable per-mitting and compliance requirements.49 These special permits simplify the regulatory process for similar facilities so that industry and the regulators need not expend limited resources for site-specific permit development for such facilities.50 Several traditional producer states have general permits applicable to oil and gas facilities,51 and states that have more recently seen development, such as Ohio, are creating their own general permits for the oil and gas industry.52

[iv] Operating PermitsIn 1990, Congress enacted title V of the CAA (Title V), which requires

“major sources” of pollutants to obtain operating permits from EPA-approved state-run permitting programs.53 The state “operating permits” must include enforceable emission limits, compliance schedules, and monitoring, reporting, and record-keeping requirements.54 An operating permit is “a source-specific bible for Clean Air Act compliance” containing

48 76 Fed. Reg. 38,748, 38,767 (July 1, 2011); see also 74 Fed. Reg. 48,467, 48,476 n.10 (Sept. 23, 2009).

49 E.g., 30 Tex. Admin. Code §§ 106.351–.355. Texas has several “permits by rule” appli-cable to oil and gas activities, such as saltwater disposal from petroleum production and handling gases and liquids associated with production, conditioning, processing, and pipe-line transfer.

50 76 Fed. Reg. 38,748, 38,767 (July 1, 2011).51 E.g., Okla. Dep’t of Envtl. Quality, Air Quality Div., “Guidance: Minor Source General

Permit for Oil & Gas Facilities” (Mar. 1, 2012) (Okla. Minor Source Guidance), http://www.deq.state.ok.us/aqdnew/permitting/AdviceDocuments.htm.

52 Ohio EPA, Air Pollution Control Div., “Oil and Gas Well-Site Production Operations GP 12” (effective Jan. 31, 2012), http://www.epa.ohio.gov/dapc/genpermit/oil_gas_gp12.aspx.

53 Clean Air Act Amendments of 1990, Pub. L. No. 101-549, §§ 501–507, 104 Stat. 2399, 2635–48 (1990) (codified at 42 U.S.C. §§ 7661–7661f); see generally MacClarence v. EPA, 596 F.3d 1123, 1125–26 (9th Cir. 2010).

54 42 U.S.C. § 7661c(a).


all requirements relevant to a pollution source in a single file.55 Accord-ingly, an operating permit will specify the operations allowed, the source’s emission limits, and the testing, monitoring, record-keeping, and report-ing requirements that assure ongoing compliance with the applicable regulations. Title V does not itself impose additional substantive emissions limits,56 although regulators can impose additional monitoring in a Title V permit.

Title V allows both EPA and public review of permits.57 After a permit-ting authority receives an application for a Title V permit, it must submit a copy of the application and the draft permit to EPA,58 and provide the public with notice and opportunity to comment on the draft permit.59 At that point, either the EPA administrator can object to issuance of the permit, or any other person can ask the administrator to object.60 If the administrator objects to issuance of the draft permit, then the permitting authority may not issue the permit until revising it to meet the objection.61 Opponents of oil and gas development projects frequently use the Title V comment period and related appeal rights to object to permits, with increasing success.62

[4] Requirements for New and Modified SourcesThe CAA requires EPA to establish nationally uniform emission stan-

dards for new and modified stationary sources falling within particular industrial categories, i.e., new source performance standards (NSPS).63 EPA publishes and periodically revises a list of industry categories, and adopts performance standards reflecting “the degree of emission limitation

55 North Carolina ex rel. Cooper v. Tenn. Valley Auth., 615 F.3d 291, 300 (4th Cir. 2010) (citing Virginia v. Browner, 80 F.3d 869, 873 (4th Cir. 1996)).

56 40 C.F.R. § 70.1(b). However, EPA Region 8 utilized Title V permitting for 10 years as a mechanism for creating “synthetic minor” limitations for certain oil and gas facilities in Indian country.

57 42 U.S.C. § 7661d; 40 C.F.R. § 70.8(d).58 42 U.S.C. § 7661d(a)(1)(B).59 40 C.F.R. § 70.7(h).60 42 U.S.C. § 7661d(b)(1), (2). The petition must be based on objections that were made

with reasonable specificity during the public comment period on the draft permit. Id.61 Id. § 7661d(b)(3), (c).62 See, e.g., Order Granting Petition for Objection to Permit, In re Williams Four Corners,

LLC, Sims Mesa CDP Compressor Station, EPA Pet. No. VI-2011-__ (July 29, 2011) (EPA permit decision addressing multiple challenges grounded in different aspects of the CAA).

63 42 U.S.C. § 7411(b).


achievable through the application of the best system of emission reduc-tion . . . .”64 EPA develops and implements the performance standards, which apply to specifically designated new or modified “affected” facilities and equipment,65 and then delegates them to the states.66 However, EPA retains authority to implement and enforce the standards after delega-tion.67 In the 1980s, EPA established performance standards for natural gas processing plants.68 EPA has recently greatly expanded the universe of covered facilities and equipment.69

[5] Standards for Hazardous Air Pollutants for New and Existing Sources

The CAA also requires EPA to establish uniform national standards oriented toward controlling specific hazardous air pollutants (HAP), i.e., national emission standards for hazardous air pollutants (NESHAP).70 The act lists regulated HAPs and then requires EPA to develop a list of source categories that emit them in significant quantities.71 EPA then develops “maximum achievable control technology” (MACT) standards for new and existing sources based on the degree of emission control achievable through the application of technologies used by the best performing sources in a given category.72 As with performance standards, EPA develops and implements the emissions standards and then delegates them to the states; however, even after delegating, EPA retains authority to implement and enforce the NESHAPs.73 The emission standards apply to facilities if their HAP emissions exceed certain threshold amounts, rendering a facility a “major source.”74 Upstream and midstream oil and gas operations may emit HAPs such as n-hexane, formaldehyde, and “BTEX,” i.e., benzene,

64 Id. § 7411(a).65 E.g., 40 C.F.R. § 60.630(b) (applicability of performance standards for equipment leaks

from onshore natural gas plants).66 42 U.S.C. § 7411(c).67 Id. § 7411(c)(2); see also 66 Fed. Reg. 13,438 (Mar. 6, 2001).68 See 50 Fed. Reg. 40,158, 40,160 (Oct. 1, 1985) (codified at 40 C.F.R. §§ 60.640–.648); 50

Fed. Reg. 26,122, 26,124 (June 24, 1985) (codified at 40 C.F.R. §§ 60.630–.636).69 77 Fed. Reg. 49,490 (Aug. 16, 2012) (to be codified at 40 C.F.R. §§ 60.5360–.5430).70 42 U.S.C. § 7412(d).71 Id. § 7412(c).72 Id. § 7412(d)(3), (g)(2).73 Id. § 7412(l).74 Id. § 7412(a)(1), (d).


toluene, ethylbenzene, and xylene, as well as hydrogen sulfide (H2S) and SO2, which production and processing operations may emit when they handle and treat “sour gas.”75

[6] State PrimacyWhile EPA targets the oil and gas industry with federal regulations, it

is critical to remember that the CAA gives the states primary responsibil-ity to achieve air quality standards.76 For example, states typically adopt federal NSPS and NESHAP regulations, and most permitting is done at the state level.77 While the federal standards have talismanic influence because the states incorporate them by reference, states are reacting to increased development with extensive regulatory initiatives of their own, based on regional air quality conditions and oil and gas development-specific refinement of long-standing permitting regimes.78

Operators must vigilantly monitor and comply with state rules, which vary by state and even producing region. For example, as development has rapidly increased in shale plays, states have reacted equally quickly with regulations and guidance that restrict emissions for operators in those particular regions.79 States confront operators with a dizzying and ever-changing array of forms, permits, and informal guidance.80 Some states have responded to the increased pace of permit applications with “general permits” or “permits by rule” applicable to certain oil and gas facilities or equipment. These can streamline the permitting process.81

75 76 Fed. Reg. 52,738, 52,745, 52,778 (Aug. 23, 2011).76 42 U.S.C. § 7407; James E. McCarthy et al., Cong. Research Serv., RL30853, “Clean Air

Act: A Summary of the Act and Its Major Requirements,” at 3–4 (2011).77 E.g., 66 Fed. Reg. 13,438 (Mar. 6, 2001); see also EPA, Office of Air Quality Planning

and Standards, “Good Practices Manual for Delegation of NSPS and NESHAPS,” at 2 (Feb. 1983).

78 See generally Lee Gribovicz, Western Regional Air Partnership, “Analysis of States’ and EPA Oil & Gas Air Emissions Control Requirements for Selected Basins in the Western United States,” at 19–22 (Nov. 28, 2011; errata corrections Jan. 8, 2012).

79 See, e.g., Bakken Guidance, supra note 27; Wyo. Air Quality Standards and Regula-tions, ch. 6, § 2. EPA recently listed several state guidance documents upon which it relied when it promulgated new air quality regulations applicable to oil and gas production on the Fort Berthold Indian Reservation in North Dakota. 77 Fed. Reg. 48,878, 48,884 (Aug. 15, 2012) (citing regulations and guidance from Colorado, Montana, New Mexico, Oklahoma, Texas, Utah, and Wyoming).

80 See, e.g., Wyo. Dep’t of Envtl. Quality, “Oil and Gas—Forms and Guidance Docu-ments,” http://deq.state.wy.us/aqd/oilgas.asp; see also Gribovicz, supra note 78, at 19–22.

81 See, e.g., 30 Tex. Admin. Code §§ 106.351–.355; Okla. Minor Source Guidance, supra note 51.


[7] Other Sources of Air Quality Control: Federal Agencies, Oil and Gas Commissions, and Local Governments

EPA and state air permitting agencies do not regulate oil and gas develop-ment in the Intermountain West on their own. Depending on the location of the hydrocarbons, a variety of other national, state, and local regulatory regimes may govern oil and gas production.82 At the national level, NEPA has played a central role in shaping land use decisions and energy policy for over 40 years. Oil and gas leasing and development may warrant numerous environmental reviews. In a possibly seismic shift, EPA and other federal agencies are using NEPA to impose air quality-related restrictions and lease stipulations on leasing and development projects in the West. Increasingly, interest groups challenge these projects on grounds that the agencies have not adequately considered air quality impacts. The alleged impacts range from ground-level ozone to global warming. Although the challengers face a tough burden to win such NEPA appeals on the merits, they can cause lengthy, expensive delays for proposed projects.83

At the state level, the state environmental agencies share responsibility for regulating oil and gas activities with other agencies. Several state oil and gas commissions regulate the drilling for and production and gathering of oil and gas through requirements for drilling permits, spacing, drilling, plugging, and abandonment methods, and the protection of fresh water resources. Increasingly, state oil and gas commissions also regulate air qual-ity impacts of upstream and midstream activities. For example, the Colo-rado Oil and Gas Conservation Commission (COGCC) requires operators to control fugitive dust by employing practices such as speed reduction and regular road maintenance, and restricts construction of oil and gas facilities during windy days.84 Moreover, various state commissions have addressed concerns over well-completion emissions. Some states require

82 Wilderness Workshop v. Crockett, No. 1:11-cv-1534-AP, 2012 WL 1834488, at *1 (D. Colo. May 21, 2012).

83 Western Energy Alliance, “Economic Impacts of Oil & Gas Development on Public Lands in the West,” at 13–14, 17–18, 22, 25–27 (Apr. 2012). The study found that NEPA-related delays prevented the creation of 64,805 jobs, $4.3 billion in wages, and $14.9 billion in economic impact every year. Id. at Executive Summary.

84 2 Colo. Code Regs. § 404-1:805(c); see also Colo. Dep’t of Local Affairs, “Oil and Gas Regulation: A Guide for Local Governments,” at 25 (2010).


combustion of such emissions,85 while others require practices intended to capture gas and condensate vapors under various circumstances.86

Moreover, regulation at the local level is also a fact of life for oil and gas operators. The unique nature of oil and gas activities and potential for concentrated environmental impacts has ushered a not-in-my-backyard response. This response has manifested itself in increased studies and threatened to slow or stop development through implementation of local bans and moratoria. By the end of July 2012, hundreds of local governing entities in 15 states had taken measures designed to ban or place moratoria on hydraulic fracturing.87

§ 6.03 Emission Sources and Control Technologies Affecting Oil and Gas Operations

The next several subsections describe upstream and midstream equip-ment and operations that may cause air emissions, and identify certain control technologies and strategies currently prevalent for controlling those emissions.88

[1] Drilling and CompletionsWell drilling and associated activities, such as hydraulic fracturing and

well completions, may cause emissions. Drilling rigs typically rely on die-sel engines, which emit NOx, a so-called ozone precursor.89 The well site is also a source of VOCs, another ozone precursor. For example, opera-tors increasingly rely on hydraulic fracturing after drilling is complete to fracture the formation containing the resource.90 During flowback, por-tions of the fracture fluids and reservoir gas flow back to the well head, and VOCs can escape to the atmosphere if not captured.91 Several states

85 E.g., Mont. Admin. R. 36.22.1221(1).86 E.g., 2 Colo. Code Regs. § 404-1:805(b)(3).87 E.g., Town of Erie, Colo., “Oil & Gas Operations,” http://www.erieco.gov/ (select “Oil &

Gas Operations”); see Food & Water Watch, “Local Actions Against Fracking” (listing local measures taken against hydraulic fracturing activities), http://www.foodandwaterwatch.org/water/fracking/fracking-action-center/local-action-documents/.

88 See generally EPA, “Regulatory Impact Analysis, Final New Source Performance Stan-dards and Amendments to the National Emissions Standards for the Oil and Natural Gas Industry,” at 3-1 to 3-9 (Apr. 2012) (EPA Regulatory Impact Analysis).

89 EPA defines NOx to include “all forms of oxidized nitrogen compounds.” EPA, “Inte-grated Science Assessment for Oxides of Nitrogen—Health Criteria,” at ch. 1 (July 2008).

90 Natural Resources Law Center, Intermountain Oil and Gas BMP Project, “Hydraulic Fracturing,” http://www.oilandgasbmps.org/resources/fracing.php.

91 See 76 Fed. Reg. 52,738, 52,756 (Aug. 23, 2011).


already require combustion92 or capture93 of these emissions in certain cir-cumstances, and EPA recently promulgated similar federal regulations.94

[2] FlaringNewly drilled wells bring natural gas and condensate vapors from the

subsurface. Sometimes, operators cannot immediately transfer the natural gas into a gathering pipeline and processing plant infrastructure, and must temporarily flare the gas into the atmosphere.95 Even after an operator connects the oil and gas well to such facilities, excessive line pressures or mechanical problems may necessitate short-term flaring.96

[3] TanksHydrocarbon liquid storage tanks are ubiquitous in upstream and mid-

stream operations. At the well site, operators extract the hydrocarbons and separate the mixture of liquid hydrocarbons and gas from water and solids.97 Operators typically store crude oil, condensate, and produced water in fixed-roof storage tanks.98 Operators often remove liquids at mid-stream facilities as well. Storage tanks may emit VOCs through working, breathing, and flash losses. For example, flash losses occur when crude oils or condensates flow into a storage tank from a processing vessel operated at a higher pressure.99 Controls for tank emissions generally involve a com-bustion or flare process, but may also involve vapor recovery.100

92 E.g., Mont. Admin. R. 36.22.1221(1).93 2 Colo. Code Regs. § 404-1:805(b)(3) (COGCC regulation); Wyo. Dep’t of Envtl. Qual-

ity, “Oil and Gas Production Facilities Chapter 6, Section 2 Permitting Guidance,” at 15, 20 (revised ed. Mar. 2010) (Wyo. Permitting Guidance); see generally Gribovicz, supra note 78, at 20.

94 77 Fed. Reg. 49,490, 49,543–44 (Aug. 16, 2012) (to be codified at 40 C.F.R. § 60.5375).95 U.S. Gov’t Accountability Office, GAO-04-809, “Natural Gas Flaring and Venting:

Opportunities to Improve Data and Reduce Emissions,” at 2-4 (2004).96 Id.97 See generally EPA Regulatory Impact Analysis, supra note 88, at 2-5.98 76 Fed. Reg. 52,738, 52,763–64 (Aug. 23, 2011).99 Id.100 40 C.F.R. § 63.766; see also 77 Fed. Reg. 49,490, 49,544 (Aug. 16, 2012) (to be codified

at 40 C.F.R. § 60.5395); accord, e.g., 5 Colo. Code Regs. § 1001-9:XVII.C; Mont. Admin. R. 17.8.1603(1)(b); N.D. Admin. Code § 33-15-07; Utah Admin. Code r. 307-327; Wyo. Permitting Guidance, supra note 93, at 15, 20.


[4] Processing and DehydrationOperators sometimes must remove water from the natural gas stream.101

Glycol dehydrators remove water vapor from natural gas streams at well sites and compressor facilities.102 The glycol desiccants absorb VOCs that operators then vent or route to a control device, which is often a combus-tor or flare.103 Large gas plants remove additional impurities from the gas stream by various processes.104

[5] CompressionOperators compress natural gas at many locations throughout upstream

and midstream operations to move the gas along through the pipeline network. They use combustion turbines as well as reciprocating internal combustion engines (RICE), which may emit federally designated HAPs and, depending on the type of RICE, may emit significant amounts of NOx, VOCs, and CO.105 Many complex regulations apply to RICE, and opera-tors typically use an oxidizing catalyst that removes various pollutants as a control.106

[6] Equipment LeaksSeveral process and operation components may leak VOCs. Operators

cannot avoid occasional leaks even using best practices. For example, pumps, pressure relief valves, flanges, agitators, and compressors can leak due to seal failure.107 In addition, these components can corrode. The emissions from such leaks are called “fugitive” emissions. Natural gas wells, gas plants, compressor stations, and other operations all may have fugitive emissions. Various regulations and permits may require operators to implement leak detection and repair (LDAR) programs to address this issue.108 Increasingly, operators (and inspectors) rely on infrared cameras to detect fugitive emissions.

101 See 76 Fed. Reg. 52,738, 52,744 (Aug. 23, 2011).102 EPA Regulatory Impact Analysis, supra note 88, at 2-7.103 See 40 C.F.R. § 63.765; accord 5 Colo. Code Regs. § 1001-9:XII.H; Wyo. Permitting

Guidance, supra note 93, at 15, 20.104 EPA Regulatory Impact Analysis, supra note 88, at 2-7 to 2-8.105 See 76 Fed. Reg. 52,738, 52,745 (Aug. 23, 2011).106 See 77 Fed. Reg. 33,812, 33,820 (June 7, 2012).107 See generally EPA Regulatory Impact Analysis, supra note 88, at 3-3 to 3-4.108 40 C.F.R. §§ 60.630–.636, 63.769, 63.1283(c)(3); see also 77 Fed. Reg. 49,490, 49,545–

46 (Aug. 16, 2012) (to be codified at 40 C.F.R. §§ 60.5400–.5402); accord 5 Colo. Code Regs. § 1001-9:XII.G.1.


§ 6.04 New and Revised Standards for Oil and Gas Operations[1] NSPS OOOO

Until this year, federal NSPS for the oil and gas production sector applied only to natural gas processing plants. As noted, states have long controlled oil and gas upstream and midstream emissions through preconstruction permitting programs. Nevertheless, on August 16, 2012, EPA published additional NSPS for this sector, creating a new “Subpart OOOO” (NSPS OOOO).109 EPA’s shift of focus to air emissions from completions arrives against the backdrop of repeated, unsuccessful attempts to demonstrate a strong causal link between hydraulic fracturing and drinking water contamination.110 In civil litigation, recent successes by oil and gas opera-tors tend to show that most landowners do not fully understand well-completion techniques and may have difficulty demonstrating causation, which is frequently an essential element of their theories of liability.111 Accordingly, at least one Colorado court has required plaintiffs to make a pre-discovery prima facie showing of causation and exposure in order to narrow discovery, and dismissed the plaintiffs’ claims with prejudice when they failed to do so.112 As the groundwater issue has apparently begun to lose traction, the thrust of the narrative that hydraulic fracturing is a men-ace to the environment has shifted to air quality.113

Most controversially, NSPS OOOO requires the use of “green comple-tions” for certain hydraulically fractured natural gas wells beginning

109 77 Fed. Reg. 49,490, 49,542–600 (Aug. 16, 2012) (to be codified at 40 C.F.R. §§ 60.5360–.5430). Nine groups, including Western Energy Alliance, have petitioned the U.S. Court of Appeals for the D.C. Circuit for review of this final rule. See W. Energy Alli-ance v. EPA, No. 12-1412 (D.C. Cir. filed Oct. 15, 2012).

110 Colin Harris, “Why Anti-Fracking Groups Are Shifting Their Story from Water to Air Quality,” Forbes (May 8, 2012); see also, e.g., Joint Stipulation of Dismissal Without Preju-dice Pursuant to Fed. R. Civ. P. 41(a)(1)(A)(ii) and (a)(1)(B), United States v. Range Prod. Co., No. 3:11-CV-00116-F (N.D. Tex. Mar. 30, 2012) (acknowledging EPA’s withdrawal of a CWA administrative order coming shortly on the heels of the U.S. Supreme Court’s recent holding that property owners can appeal such orders as final agency actions in Sackett v. EPA, 132 S. Ct. 1367, 1369–74 (2012)); Nathaniel R. Warner et al., “Geochemical Evidence for Possible Natural Migration of Marcellus Formation Brine to Shallow Aquifers in Penn-sylvania,” 109 Proc. Nat’l Acad. Sci. USA 11961 (July 24, 2012).

111 See generally Jeffrey C. King et al., “Factual Causation: The Missing Link in Hydraulic Fracture-Groundwater Contamination Litigation,” 22 Duke Envtl. L. & Pol’y F. 341, 349 (2012).

112 Strudley v. Antero Res. Corp., No. 2011-CV-2218 (Colo. Dist. Ct. May 9, 2012).113 See Harris, supra note 110.

§ 6.04[1][a] Air Quality Regulations 6-21

January 1, 2015.114 EPA provided the phase-in period because the oil field services and drilling sector lacks sufficient equipment and personnel to allow for immediate compliance with the new rules.115 Among other things, the new performance standards also (1) require emissions reduc-tions from seals for centrifugal compressors and replacement of piston rod-packing systems for reciprocating compressors; (2) regulate contin-uous-bleed, natural gas-driven pneumatic controllers at wells and natural gas processing plants; (3) impose stringent requirements to reduce VOC emissions from storage tanks; and (4) tighten the definition of a “leak” for LDAR purposes.116

[a] Hydraulic Fracturing for Gas WellsThe new performance standards cover onshore wells drilled principally

for production of natural gas, and target VOC emissions during the “flow-back” stage of hydraulic fracturing.117 NSPS OOOO requires the use of “reduced emission completion” technology, i.e., “green completions,” to reduce VOC emissions, and completion combustion devices, such as pit flaring. In a green completion, equipment separates the multiphase flow, e.g., gas and liquid hydrocarbons and sand, from the flowback that comes from the well and transfers the natural gas to a pipeline.

Moreover, the green completion requirement will not apply to all wells. For “exploratory” (i.e., “wildcat”) and “delineation” wells, and for wells in low-pressure reservoirs (as determined by a formula), EPA will only require combustion of emissions. But EPA will require green completions combined with combustion for all other completed or recompleted natural gas wells.118 Also, in order to provide an incentive for the use of green completions prior to 2015, EPA will not call recompletions using green-completion techniques “modifications,” so such recompletions will not trigger NSPS applicability.119

114 77 Fed. Reg. 49,490, 49,543–44 (Aug. 16, 2012) (to be codified at 40 C.F.R. §§ 60.5370(a), .5375).

115 Id. at 49,517–19; see also Letter from Jack Gerard, President & CEO, Am. Petroleum Inst., to Lisa Jackson, Administrator, EPA 2 (Apr. 12, 2011).

116 77 Fed. Reg. at 49,544–46 (to be codified at 40 C.F.R. §§ 60.5380, .5385, .5390, .5395, .5401(b)(2)).

117 Id. at 49,543–44 (to be codified at 40 C.F.R. §§ 60.5370, .5375).118 Id.119 Id. at 49,543 (to be codified at 40 C.F.R. § 60.5365(h)(2)).

6-22 Mineral Law Institute § 6.04[1][b]

[b] Oil WellsThe new performance standards also do not apply to wells drilled prin-

cipally for the production of crude oil.120 Outcry and confusion regard-ing the scope of the new rules may cause EPA or Congress to reconsider whether to extend the completion standards to oil wells in addition to gas wells.121 Moreover, EPA recently promulgated rules regulating both oil and gas wells on the Fort Berthold Indian Reservation in North Dakota.122

[c] CompressorsThe new performance standards regulate VOC emissions from recip-

rocating compressors powered by reciprocating spark ignition engines and from centrifugal compressors powered by turbines.123 EPA originally proposed to require the use of dry seals on all centrifugal compressors. But, after receiving comments questioning the technical feasibility of using dry seals on certain regulated equipment, EPA is also allowing the use of wet seals in the new performance standards as long as operators capture the emissions and route them to a control device that achieves a 95% reduc-tion of VOCs.124 For reciprocating compressors, the new performance standards require replacement of rod packing systems either every 26,000 hours of operation or every 36 months.125 The rule appears to require that operators start counting hours and months from the effective date of the rule, and not from the August 23, 2011, applicability date.126

[d] Pneumatic ControllersThe new performance standards also regulate continuous-bleed, natural

gas-driven pneumatic controllers, which control valve movements at wells and natural gas processing plants. The final rules limited applicability of the standards to “high-bleed” controllers as long as they are not located at

120 Id. at 49,516.121 E.g., Letter from Henry A. Waxman, Ranking Member, U.S. House of Representatives

Comm. on Energy and Commerce, to Fred Upton, Chairman, U.S. House of Representa-tives Comm. on Energy and Commerce (May 14, 2012).

122 77 Fed. Reg. 48,878, 48,893 (Aug. 15, 2012) (to be codified at 40 C.F.R. § 49.140(a)).123 77 Fed. Reg. 49,490, 49,544 (Aug. 16, 2012) (to be codified at 40 C.F.R. §§ 60.5380,

.5385).124 Id. at 49,499–500, 49,523.125 Id. at 49,544, 49,556 (to be codified at 40 C.F.R. §§ 60.5385(a), .5415(c)(3)).126 The rule is potentially ambiguous. It specifically requires operators to start counting

hours beginning on the effective date at the earliest. However, it does not have such specific language for counting months, leaving open the possibility that the month-counting com-pliance option is more stringent than the hours-counting option. See id. at 49,544.

§ 6.04[1][e] Air Quality Regulations 6-23

a natural gas processing plant.127 However, EPA is imposing a zero-bleed limit for each controller at a natural gas processing plant.128 By narrowing the “affected facility” definition to exclude low-bleed controllers (except at processing plants), EPA made it possible for operators who install such low-bleed controllers prior to the effective date of the new rules to avoid the significant burdens of compliance with the NSPS. EPA provided a one-year phase-in period for the new pneumatic controller performance standards.129

[e] Storage VesselsUnder the new performance standards, vessels with VOC emissions

of at least six tpy must achieve 95% reduction in VOC emissions.130 EPA originally proposed to determine applicability based on crude oil and condensate throughput, but found that procedure unworkable.131 The proposed performance standards also contained several cross-references to NESHAP subpt. HH (NESHAP HH),132 which is a very complex and burdensome regulation. In the final rules, EPA has incorporated storage vessel requirements from NESHAP HH directly into the performance standards.133 There is a one-year phase-in period for the new storage ves-sel performance standards.134 EPA also provided two additional regulatory grace periods for vessels at well sites. For vessels at new well sites, EPA has provided 30 days to determine whether the vessels will trigger the six tpy VOC threshold, and then an additional 30 days to install and operate a control device.135 On the other hand, EPA has not provided the grace period for storage vessels at producing well sites.

127 Id. at 49,520. The final performance standards deviate from the proposed standards by narrowing the “affected facility” definition to exclude low-bleed controllers. In addi-tion, the new standards do not regulate pneumatic controllers located in the natural gas transmission and storage segments. EPA also provided exemptions from the performance standards for certain situations, such as the use of controllers on large emergency shutdown valves.

128 Id. at 49,544 (to be codified at 40 C.F.R. § 60.5390(b)(1)).129 Id. (to be codified at 40 C.F.R. § 60.5390(c)(1)).130 Id. at 49,544–45 (to be codified at 40 C.F.R. § 60.5395).131 Id. at 49,500.132 See 40 C.F.R. §§ 63.760–.777.133 77 Fed. Reg. at 49,500.134 Id. at 49,544–45 (to be codified at 40 C.F.R. § 60.5395).135 Id. at 49,500.


The performance standards for storage tanks offer potential assistance to some operators, but also introduce many new challenges. For example, NSPS OOOO arguably benefits operators in Indian country because it provides a “federally enforceable” basis for reducing PTE below thresholds. However, there may be applicability issues for several reasons. Operators may not have records to establish when they constructed certain tanks, because they frequently keep records for well sites based on rig-up, drill-ing, production, etc., not based on surface site development. The new rules also may not let operators avoid applicability by switching throughput from one tank to another in a tank battery in order to keep each individual tank under the applicability threshold. They also do not clarify whether operators may estimate emissions using production decline curves, which would provide more accurate estimates, or without production decline curves, which would provide inaccurate but conservative results. Mean-while, there may be difficulty obtaining the emissions controls necessary for compliance. EPA’s grace periods for determining applicability may not provide operators enough time to make meaningful determinations. Based on this small sample of applicability issues, NSPS OOOO presents too long a list of potential operational challenges for full treatment in this chapter.

[2] NSPS KKKThe natural gas plant equipment leak performance standards apply to

two types of “affected facilities”: compressors and process units at natural gas plants.136 The standards specifically apply to compressors and equip-ment including valves, pumps, pressure relief devices, flanges and connec-tors, and open-ended lines that contain or contact a process fluid or inlet gas,137 and require an LDAR program.138 Regulators review compliance with LDAR through inspections and review of records.139 In the new NSPS OOOO, EPA revised the LDAR requirements by lowering the definition of “leak” in newly constructed or modified natural gas plants from 10,000 ppm to 500 ppm.140

136 40 C.F.R. § 60.630(a)(1)–(3); 50 Fed. Reg. 26,122 (June 24, 1985). A “process unit” generally includes equipment used to extract NGLs from field gas or fractionate liquids. 40 C.F.R. § 60.631.

137 50 Fed. Reg. 26,122 (June 24, 1985).138 40 C.F.R. § 60.632.139 See id. §§ 60.635, .636.140 77 Fed. Reg. 49,490, 49,545 (Aug. 16, 2012) (to be codified at 40 C.F.R. § 60.5401(b)

(2)).


[3] NSPS LLLThe natural gas plant SO2 standards require sweetening unit operators

to reduce SO2 emissions using sulfur recovery technology.141 The required emission reduction efficiency varies with the sulfur feed rate and concen-tration of H2S in the gas entering the sulfur recovery unit.142 In the new NSPS OOOO, EPA revised the sulfur recovery requirements by requiring a minimum SO2 reduction efficiency of 99.9% for newly constructed or modified natural gas plants with sweetening units that process a sulfur feed rate of at least five long tons per day with H2S content of at least 50%.143

[4] NESHAP HHIn 1999, EPA promulgated NESHAP HH in part to limit HAP emissions

from glycol dehydration units.144 The emission standards apply to owners and operators of facilities that process, upgrade, or store hydrocarbon liq-uids to the point of custody transfer, and natural gas from the well up to and including the natural gas processing plant.145 The standards limit HAP emissions from process vents on glycol dehydration units, storage vessels with flash emissions, and equipment leaks at natural gas processing plants. An oil or natural gas facility that is a major source of HAPs is required to, among other things: install MACT-level controls on the specified sources, demonstrate the effectiveness of such controls, continuously moni-tor the controls, record applicable monitoring data, and submit various notifications and reports regarding the source to assure compliance with applicable pollution control requirements.146 At the same time, EPA also promulgated standards applicable to natural gas transmission and storage facilities (NESHAP HHH).147

When it promulgated NSPS OOOO, EPA also amended existing HAP regulations applicable to the oil and gas production sector.148 For example, the revisions to NESHAP HH subject additional glycol dehydrators to

141 40 C.F.R. §§ 60.640(a), .643(a); 50 Fed. Reg. 40,158 (Oct. 1, 1985).142 40 C.F.R. § 60.642; 50 Fed. Reg. 40,158 (Oct. 1, 1985).143 77 Fed. Reg. at 49,566 (to be codified at 40 C.F.R. pt. 60, subpt. OOOO tbls. 1 & 2).144 United States v. Questar Gas Mgmt. Co., No. 2:08-CV-167TS, 2011 WL 1793239, at

*1 n.8 (D. Utah May 11, 2011) (citing 40 C.F.R. § 63.760(b)). The authors were involved in the cited case.

145 64 Fed. Reg. 32,610, 32,613 (June 17, 1999) (codified at 40 C.F.R. §§ 63.760–.777).146 40 C.F.R. §§ 63.771–.775.147 64 Fed. Reg. 32,610, 32,615 (June 17, 1999) (codified at 40 C.F.R. §§ 63.1270–.1287).148 77 Fed. Reg. 49,490, 49,568–81 (Aug. 16, 2012) (to be codified at 40 C.F.R.

§§ 63.760–.775).


emission limitations.149 EPA made similar revisions in NESHAP HHH for natural gas transmission and storage facilities. Notably, EPA also proposed to broaden the applicability of the emission standards for storage tanks, potentially subjecting thousands of additional crude oil and condensate vessels to stringent emissions limits. However, EPA ultimately did not expand the universe of storage tanks subject to regulation under the HAP program.150

EPA’s revised emission standards also define “flare” for the first time.151 This change relates to whether an operator must conduct performance test-ing on a control device. The control requirements in emission standards authorize owners and operators of affected sources at oil and gas produc-tion facilities to utilize an “enclosed combustion device,” a “vapor recovery device,” or a “flare, as defined in § 63.761, that is designed and operated in accordance with the requirements of § 63.11(b).”152 Performance testing is not required on those devices that qualify as a “flare.”153 NESHAP HH had not previously defined “flare.” Operators have questioned whether to subject a device to performance testing, or whether operators could show compliance by meeting the design criteria. The new rules now explicitly define a “flare” as “a thermal oxidation system using an open flame (i.e., without enclosure).”154 Therefore, only devices meeting this definition can avoid the more stringent compliance requirements in the regulation. For other control equipment, the revised emission standards require perfor-mance testing or manufacturers’ guarantees.155

[5] RICE Subject to NSPS and NESHAPDrilling, production, compression, and other support activities for oil

and gas operations all use various types of stationary internal combustion engines.156 Three federal regulatory programs apply to such engines: NSPS

149 Id. at 49,568–71 (to be codified at 40 C.F.R. §§ 63.760, .761, .765).150 Id. at 49,532–33.151 Id. at 49,569 (to be codified at 40 C.F.R. § 63.761).152 40 C.F.R. § 63.771(d)(1).153 Id. § 63.772(e)(1)(i).154 77 Fed. Reg. at 49,569 (codified at 40 C.F.R. § 63.761).155 Id. at 49,573–74 (codified at 40 C.F.R. § 63.772(e)).156 The term “stationary internal combustion engine” means any internal combustion

engine, except combustion turbines, that converts heat energy into mechanical work and is not mobile. 40 C.F.R. §§ 60.4219, .4248.

§ 6.04[5][b] Air Quality Regulations 6-27

IIII, NSPS JJJJ, and NESHAP ZZZZ.157 These are among the most compli-cated and confusing of all environmental regulations. Between the three programs, EPA and, through incorporation at the state level, state air agen-cies regulate air emissions from most internal combustion engines used in upstream and midstream operations.158 Operators often struggle with determining when the programs apply and how they overlap, and with the innumerable control technology monitoring, record-keeping, testing, and reporting requirements.159 This is a fertile area for state and EPA inspec-tion and enforcement.

[a] NSPS IIIIEPA promulgated NSPS IIII for compression ignition (CI) RICE in

2006.160 The standards limit emissions of NOx, PM, CO, and non-methane hydrocarbons, and also control sulfur emissions by requiring the use of low sulfur fuel.161 EPA phased in the CI RICE standards over several years and created tiers with increasing levels of stringency.162

[b] NSPS JJJJEPA promulgated NSPS JJJJ for spark ignition (SI) RICE in 2008.163 The

regulations similarly target NOx, CO, and VOCs, and also control sulfur emissions by requiring the use of low sulfur fuel.164 The standards apply to engines regardless of their size or fuel.165

157 Id. §§ 60.4200–.4219 (NSPS IIII); §§ 60.4230–.4248 (NSPS JJJJ); §§ 63.6580–.6675 (NESHAP ZZZZ).

158 See, e.g., Colo. Dep’t of Pub. Health and Env’t, Stationary Source Program, “Permitting Guidance for Oil & Gas Industry—Natural Gas Fired Reciprocating Internal Combustion Engine (RICE) General Permit GP02” (Aug. 1, 2011). For example, whereas EPA does not consider relocation of a compression ignition (CI) RICE to be a modification or construc-tion triggering NSPS applicability, Colorado does and requires compliance with NSPS IIII as a state-only requirement. Memorandum from R.K. Hancock III, Constr. Permits Unit Supervisor, Colo. Dep’t of Pub. Health and Env’t, to Stationary Sources Staff, Colo. Dep’t of Pub. Health and Env’t (Oct. 13, 2010).

159 See, e.g., Memorandum from Colo. Air Pollution Control Div., to Stationary Sources Program, Local Agencies & Regulated Community, “Guidance on State-wide RICE require-ments” (Jan. 27, 2010).

160 71 Fed. Reg. 39,154 (July 11, 2006).161 Id. at 39,156, 39,158.162 Id. at 39,156.163 73 Fed. Reg. 3568 (Jan. 18, 2008).164 Id. at 3571.165 Id. at 3570.

6-28 Mineral Law Institute § 6.04[5][c]

[c] NESHAP ZZZZEPA developed NESHAP ZZZZ in essentially three stages. First, EPA

promulgated rules covering RICE with more than 500 horsepower and located at “major sources.”166 Then, EPA promulgated rules covering new RICE with 500 horsepower or less at major sources and also all new RICE at “area sources.”167 And then, EPA added rules covering existing SI RICE at area sources, existing SI RICE with 500 horsepower or less at major sources, and existing CI RICE.168

Due to general industry concerns that operators cannot practically implement the latest stage of RICE regulations, EPA recently proposed to amend those regulations to provide alternative compliance measures and to conform certain aspects of the NSPS and NESHAP programs.169 For example, in response to oil and gas industry concerns, EPA proposed to create a new subcategory of certain SI RICE at area sources in “remote areas,” where the costs of compliance with NESHAP ZZZZ unreasonably outweigh the potential HAP reductions.170 For these RICE, EPA proposed to allow operators to demonstrate compliance through management prac-tices instead of through numeric emissions limits and associated testing and monitoring.171 The emission standards target hazardous pollutants such as formaldehyde.172 Operators must ensure their RICE comply with emission limits or fit them with emission controls, such as oxidation cata-lyst or non-selective catalytic reduction.173

Notably, two compliance dates for NESHAP ZZZZ arise in 2013. Opera-tors must comply with the standards for non-emergency CI RICE with more than 500 horsepower and located at major sources no later than May 3, 2013.174 Operators must comply with the standards for existing SI RICE with 500 horsepower or less at major sources and all existing RICE at area sources no later than October 19, 2013.175

166 69 Fed. Reg. 33,474 (June 15, 2004).167 73 Fed. Reg. 3568 (Jan. 18, 2008).168 75 Fed. Reg. 51,570 (Aug. 20, 2010); 75 Fed. Reg. 9648 (Mar. 3, 2010).169 77 Fed. Reg. 33,812, 33,813 (June 7, 2012).170 Id. at 33,820.171 Id. at 33,820–21, 33,839 (to be codified at 40 C.F.R. §§ 63.6603, .6630, .6640, .6675).172 Id. at 33,816.173 Id. at 33,820–21.174 40 C.F.R. § 63.6595(a).175 Id.


§ 6.05 Air Quality Standards: Ozone Nonattainment[1] Background

Ozone forms when VOCs, NOx, and CO react in the presence of sun-light.176 VOCs, NOx, and CO are therefore called “ozone precursors.” As discussed in § 6.02[1], above, the CAA requires EPA to establish and periodically review the air quality standards for ozone and five other pol-lutants.177 Environmental groups have attempted to force EPA to tighten permit review standards in light of EPA’s decision to make the ozone air quality standards more stringent.178 EPA promulgated the current 0.075 ppm eight-hour ozone standard in 2008.179 In 2010, EPA proposed to fur-ther tighten the ozone standard within the range of 0.060 to 0.070 ppm.180 In 2011, EPA submitted the proposal to the White House, but President Barack Obama clarified that he would not support revising the ozone stan-dards until 2013.181 The 2008 ozone standards are applicable law.182

[2] The Practical Impacts of NonattainmentStates must develop and implement plans to bring nonattainment areas

back into compliance.183 The terms of the plans depend on the severity of the nonattainment, and may include more stringent emission controls and a requirement that operators “offset” emissions from new or modi-fied sources.184 The offset requirement provides that operators must off-set increases from the proposed project by equal or greater reductions from the same source, or other sources in the area.185 For a large facility,

176 See generally Amigos Bravos v. BLM, No. 6:09-cv-00037-RB-LFG, 2011 WL 7701433, at *4 (D.N.M. Aug. 3, 2011).

177 42 U.S.C. §§ 7408, 7409.178 WildEarth Guardians v. Jackson, Nos. 11-cv-5651-YGR, 11-cv-5694-YGR, 2012 WL

1604854, at *1 (N.D. Cal. May 7, 2012). The federal court held that the CAA does not impose upon EPA a nondiscretionary duty to promulgate new, more restrictive permitting regulations.

179 73 Fed. Reg. 16,436 (Mar. 27, 2008).180 75 Fed. Reg. 2938 (Jan. 19, 2010).181 Letter from Cass R. Sunstein, Adm’r, OMB Office of Information and Regulatory

Affairs, to Lisa P. Jackson, Adm’r, EPA (Sept. 2, 2011).182 See In re: Shell Gulf of Mex., Inc. & Shell Offshore, Inc., OCS Appeal Nos. 11-02,

11-03, 11-04, 11-08, 2012 WL 119962, at *75–78 (EAB Jan. 12, 2012).183 42 U.S.C. § 7502(a)(1), (b).184 Id. §§ 7503(a)(1)(A), 7511a; see also Natural Res. Def. Council, Inc. v. S. Coast Air

Quality Mgmt. Dist., 694 F. Supp. 2d 1092, 1097 (C.D. Cal. 2010).185 42 U.S.C. § 7503(c)(1); 40 C.F.R. § 51.165(a)(3)(ii)(C)(1).

6-30 Mineral Law Institute § 6.05[3][a]

operators can often obtain offsets by shutting down or restricting emitting sources. However, for small sources, such as many oil and gas production facilities, operators may find it impractical or prohibitively expensive to obtain offsets from existing sources within the same nonattainment area, especially in rural areas where oil and gas development comprises the pri-mary industrial activity.

[3] Ozone Nonattainment Areas in the Intermountain West Associated with Oil and Gas Development[a] Denver Northern Front Range

The Denver Northern Front Range area provides a cautionary tale of the impact of ozone nonattainment on oil and gas production.186 EPA placed this area, where there is substantial oil and gas development, on the ozone nonattainment list in 2004.187 In an attempt to avoid the designation, the Denver metro area entered into an early action compact (EAC) with EPA to reduce ozone levels.188 The Denver EAC noted that oil and gas emissions may have contributed to increases in ozone concentrations, and set forth a schedule for the implementation of control measures into the Colorado SIP to comply with the ozone air quality standard.189 As a result of nonat-tainment in this area, Colorado has removed oil and gas air permitting exemptions, and promulgated stringent emission control requirements for condensate tanks, RICE, and dehydration units.190 Denver reached attainment with the ozone air quality standard in 2010;191 but after EPA promulgated a more stringent standard, it once again designated the area

186 Assessment of Environmental Implications, supra note 5, at 2-10.187 69 Fed. Reg. 23,858, 23,890 (Apr. 30, 2004).188 See 72 Fed. Reg. 9285 (Mar. 1, 2007). EPA listed several baseline requirements for

EACs in return for giving state, local, and tribal authorities flexibility in achieving reduc-tions in VOC and NOx emissions. See 70 Fed. Reg. 28,239, 28,242 (May 17, 2005).

189 Colo. Air Quality Control Comm’n, “Denver Metro Area & North Front Range Ozone Action Plan Including Revisions to the State Implementation Plan,” at i, V-12 (Dec. 12, 2008) (Denver Action Plan).

190 70 Fed. Reg. 28,239, 28,245–46 (May 17, 2005). For example, Colorado promulgated the following additions to Colorado’s “Regulation No. 7”: (1) installation of control equip-ment on condensate tanks to reduce flash emissions associated with oil and gas exploration and production, (2) installation of controls targeting VOC and NOx emissions from rich-burn and lean-burn natural gas-fired RICE engines larger than 500 horsepower, and (3) installation of controls targeting VOC emissions from dehydration units. See 5 Colo. Code Regs. § 1001-9:XVII.

191 77 Fed. Reg. 28,424, 28,431 (May 14, 2012). When EPA formally designated the Den-ver metro area as nonattainment for the 1997 ozone air quality standard, the Denver EAC came to an end. Id. at 28,427 tbl. 2, note a.

§ 6.05[3][b] Air Quality Regulations 6-31

as “marginal” nonattainment.192 Colorado is working on a revised plan, due in 2013.193

[b] Jonah/Pinedale, WyomingThe Jonah Field, which encompasses a 30,500-acre area of federal, state,

and private lands south of Yellowstone and Grand Teton National Parks in western Wyoming, contains approximately 12.8 trillion cubic feet of natu-ral gas and is one of the most highly productive sweet natural gas fields in North America.194 Over the past three years, concerns about ozone levels in certain oil and gas producing regions have garnered national attention.195 In May 2012, EPA designated the Upper Green River Basin of Wyoming, which includes the Jonah and Pinedale Anticline fields, as having “mar-ginal” nonattainment of the 2008 eight-hour ozone standard.196

Ozone nonattainment is usually attributed to high temperatures in urban areas, but air quality monitors have recorded several wintertime episodes of ozone concentrations exceeding the current ozone standards in rural portions of southwestern Wyoming.197 The snow-covered surface of southwestern Wyoming in winter appears to reflect solar radiation back up into the atmosphere, providing two bites at the apple for the photo-chemical reactions involved in ozone formation.198 Scientists and regula-tors do not fully understand the phenomenon of wintertime ground-level ozone formation, but oil and gas emissions likely play an important role.199 Other factors, such as regional transport, i.e., weather patterns carrying

192 77 Fed. Reg. 30,088, 30,110 (May 21, 2012).193 Denver Action Plan, supra note 189, at v; see also Memorandum from Colo. Office

of Legislative Legal Servs., to Colo. Legislative Council, “H.B. 10-1365 and Regional Haze State Implementation Plan,” at 2-4 (Mar. 16, 2011), http://www.state.co.us/gov_dir/leg_dir/olls/PDF/rr0100585tm.pdf.

194 Wyo. Outdoor Council, 176 IBLA 15, 18, GFS(O&G) 15(2008).195 E.g., Scott Streater, “Air Quality Concerns May Dictate Uintah Basin’s Natural Gas

Drilling Future,” N.Y. Times, Oct. 1, 2010.196 77 Fed. Reg. 30,088, 30,157–58 (May 21, 2012).197 Till Stoeckenius et al., “A Conceptual Model of Winter Ozone Episodes in Southwest

Wyoming,” at 1-1 (Jan. 29, 2010).198 William P.L. Carter & John H. Seinfeld, “Winter Ozone Formation and VOC Incre-

mental Reactivities in the Upper Green River Basin of Wyoming,” 50 Atmospheric Env’t 255, 255, 264 (2012). More specifically, they argue that the occurrence of the wintertime ozone spikes is a result of VOC and NOx emissions from natural gas production operations combined with occasional low atmospheric inversions, stagnant conditions, and enhanced ultraviolet intensity due to the high albedo of the snow-covered surface.

199 BLM, “Environmental Assessment for the Colorado Oil Shale Research, Develop-ment, and Demonstration (RD&D) Lease Tracts Project,” at 56 (Preliminary, May 2012).

6-32 Mineral Law Institute § 6.05[3][c]

ozone emissions into rural Intermountain West regions, may also cause high ozone levels.200

Ozone nonattainment may create special problems in the Jonah Field and similar oil and gas regions. An operator’s ability to find offsets depends partly on the prevailing statutes and regulations in the newly nonattain-ment area. In areas without stringent preexisting air quality laws, the relevant regulatory authority can take basic measures that lead to sharp decreases in emissions. However, in other places, such as Wyoming, that have proactively implemented stringent emissions requirements already, regulators have already picked the low-hanging regulatory fruit.201 More-over, while urban areas may have several existing emissions sources that can provide offsets, rural areas may not have sufficient industrial diversity and development to achieve the offsets required by a Nonattainment NSR permit. In light of these challenges, Wyoming’s environmental agency has convened a task force to advise and recommend approaches for finding solutions to nonattainment issues given the economic dependence of the Jonah Field area, and Wyoming as a whole, on oil and gas development.202 The CAA’s requirement that certain federal permitting actions on public lands must ensure compliance with the applicable SIP exacerbates the pragmatic challenges posed by nonattainment.203 Accordingly, operators might struggle to carry out new development in rural nonattainment areas where the oil and gas development comprises the primary industry.

[c] Uintah Basin, UtahWhen EPA made its nonattainment designation for the Upper Green

River Basin, EPA also acknowledged the potential causal link between Intermountain West wintertime ozone levels and oil and gas emissions in the Uintah Basin, Utah.204 EPA designated the Uintah Basin as “unclas-sifiable” on the basis that “unofficial” monitoring in the area had detected ozone levels exceeding the air quality standards, but EPA did not have suf-

200 See Amigos Bravos v. BLM, No. 6:09-cv-00037-RB-LFG, 2011 WL 7701433, at *11 (D.N.M. Aug. 3, 2011) (“BLM again concluded that ‘[a]ir quality in the area of the proposed lease tracts is generally good,’ acknowledged the high ozone levels in San Juan County . . . but concluded they were the result of ‘regional transport and high natural biogenic source emissions,’ not increased oil and gas development.” (quoting documents from the BLM July 2008 lease sale (JUL 95-124))).

201 See Ruckelshaus Institute of Env’t and Natural Res., Univ. of Wyo., “Upper Green River Basin Air Quality Citizens Advisory Task Force, Situation Assessment and Process Recommendations,” at 1 (Feb. 21, 2012).

202 Id. at 1, 3.203 42 U.S.C. § 7506(c).204 77 Fed. Reg. 30,088, 30,089 (May 21, 2012).

§ 6.06 Air Quality Regulations 6-33

ficient “official” monitoring to determine the area’s attainment status.205 There is an intensive ozone monitoring program ongoing.206

[4] Ozone Advance ProgramEPA has launched several programs similar to the EAC designed to help

state, local, and tribal governments avoid violations of the ozone air quality standards. For example, EPA recently debuted the “Ozone Advance” pro-gram.207 Participants will work with EPA to implement more stringent air emissions control measures so as to maximize multi-pollutant reductions and avoid an EPA nonattainment designation.208 EPA recommends that areas commit to the program for five-year terms.

§ 6.06 Aggregation of Oil and Gas OperationsOil and gas operations only trigger certain permitting programs if they

fit into the “major source” subset of “stationary sources.”209 The aggregation issue asks whether separate facilities constitute a single “stationary source,” so that permit writers can determine whether that “stationary source” is a “major source.” EPA’s regulations implementing these programs define the term “stationary source” as “any building, structure, facility, or instal-lation which emits or may emit a regulated . . . pollutant.”210 In turn, the regulations define “building, structure, facility, or installation” as all of the pollutant-emitting activities that: (1) belong to the same industrial group-ing, i.e., have the same two-digit Standard Industrial Classification “Major Group”; (2) are located on one or more contiguous or adjacent proper-ties; and (3) are under the control of the same person (or persons under common control).211 This three-part test for determining whether separate

205 Id. at 30,089–90. But see Amigos Bravos, 2011 WL 7701433, at *32 (“[T]he Court is reluctant to conclude that, as a matter of law, any EIS lacking quantitative ozone dispersion modeling fails NEPA’s hard look requirement.”).

206 Judy Fahys, “Officials Kick Off Uinta Basin Pollution Study,” Salt Lake Tribune, Feb. 7, 2012; see also Utah State Univ. Res. Found., Energy Dynamics Lab., “2012 Uintah Basin Winter Ozone and Air Quality Study” (Mar. 2012 Update); Brock LeBaron, Utah Dep’t of Envtl. Quality, “Uintah Basin Winter Ozone Study Plan and Budget,” at 5 (Draft Version 3.0, Oct. 18, 2011) (discussing potential to use new monitoring data when evaluating new oil and gas production activity).

207 Memorandum from Stephen D. Page, Director, EPA Office of Air Quality Planning and Standards, to EPA Regional Air Div. Directors, Regions 1–10, at 1 (Apr. 4, 2012).

208 Id. at 2; see also EPA, “Ozone Advance Guidance,” at 2, 8–9 (Apr. 4, 2012 est. date).209 42 U.S.C. §§ 7475, 7661a; see Summit Petroleum Corp. v. EPA, 690 F.3d 733, 736–37

(6th Cir. 2012) (one of the authors participated in the cited case).210 E.g., 40 C.F.R. § 52.21(b)(5).211 Id. § 52.21(b)(6); accord id. §§ 51.166(b)(6), 70.2, 71.2; see generally 45 Fed. Reg.

52,676, 52,694–95 (Aug. 7, 1980) (Preamble to the 1980 PSD Regulations).


facilities constitute one “stationary source” has become a controversial aspect of oil and gas air quality regulation.212

All three prongs of the test must be satisfied to aggregate emissions from separate facilities. EPA’s aggregation test straightforwardly requires emis-sions sources to be physically “contiguous or adjacent” before regulators can treat them as a single “plant,” but EPA has never established a bright line physical distance defining “adjacent.”213 Over the years, EPA has provided inconsistent guidance on the aggregation of pollutant-emitting activities and the designation of “major sources” and “major stationary sources.”214 When it promulgated the PSD regulations, EPA clarified that “it does not intend ‘source’ to encompass activities that would be many miles apart along a long-line operation,” such as pumping stations along a pipeline.215 Although EPA refused to provide specific guidance on how far apart activi-ties could be and still be considered “adjacent,” it responded to a comment by indicating that operations located 20 miles apart and connected by a dedicated railroad line “would be too far apart.”216 While EPA left open the possibility that regulators could make an “adjacent” determination for noncontiguous facilities separated by some distance, it instructed that such a determination would have to fit within the general framework of the sta-tionary source definition and the “common sense notion of ‘plant.’ ”217

Almost immediately, federal and state permitting authorities began to seek EPA’s guidance on how to apply the “contiguous or adjacent” prong of the aggregation test. Subsequently, EPA issued various binding and nonbinding opinions and memoranda to provide the permitting authori-ties with guidance in applying aggregation principles to designate station-ary sources.218 EPA’s “adjacency” opinions for noncontiguous emissions

212 See, e.g., MacClarence v. EPA, 596 F.3d 1123 (9th Cir. 2009).213 45 Fed. Reg. 52,676, 52,694–95 (Aug. 7, 1980); see also Summit Petroleum Corp., 690

F.3d at 744–46.214 See MacClarence, 596 F.3d at 1127.215 45 Fed. Reg. at 52,695.216 Id.217 Id.218 MacClarence, 596 F.3d at 1127; compare Memorandum from EPA, Dir., Div. of Sta-

tionary Source Enforcement, to Steve Rothblatt, Chief, Air Programs Branch, EPA Region 5, “PSD Definition of Source,” (June 30, 1981) (opining that two General Motors facili-ties located one mile apart could be considered “adjacent” because they were connected by a dedicated railroad line and together produced one automobile line), with Letter from Richard R. Long, Dir., Air and Radiation Program, EPA Region 8, to Dennis Myers, Con-struction Permit Unit Leader, Air Pollution Control Div., Colo. Dep’t of Public Health and Env’t (Apr. 20, 1999) (with regard to the American Soda Commercial Mine, determining


sources located miles apart often turned on its determination that a pipe-line or railroad line physically connected the separate structures.219 In 1999, EPA Region 8 responded to a request from a regulated entity for a Title V opinion by stating that each oil and gas well and its associated tank batteries and other equipment located on a single site would be considered a single source for Title V purposes, but did not suggest that the individual oil and gas well sites located throughout the 12-mile radius of the produc-tion field should be collectively aggregated as a single source.220

To dispel regulatory confusion, EPA issued guidance specific to the oil and gas industry in 2007 stating: “A reviewing authority can consider two surface sites to be in close proximity if they are physically adjacent, or if they are separated by no more than a short distance (e.g., across a highway, separated by a city block or some similar distance).”221 But EPA withdrew that guidance in 2009.222 As a result, regulators have interpreted the aggre-gation test as requiring them to conduct “complex” and “in-depth analyses of ownership and operational issues,” notwithstanding the agency’s origi-nal prohibition on such analyses.223 Recently, the oil and gas industry has had to stand and fight for the pragmatic application of the three-part test in several cases from different regions of the United States.

[1] Frederick Compressor Station—Contiguous or Adjacent

In 2011, EPA upheld a decision by the Colorado Department of Public Health and Environment (CDPHE) not to aggregate the emissions from

that “distance alone” would not preclude an “adjacent” determination for two units located roughly 40 miles apart due to functional interdependence).

219 See, e.g., Memorandum from Robert G. Kellam, EPA Office of Air Quality Planning Standards, to Richard R. Long, Dir. Air Programs, EPA Region 8 (Aug. 27, 1996) (discuss-ing “Analysis of the Applicability of PSD to the Anheuser-Busch Inc. Brewery & Nutri-Turf, Inc. Landfarm at Fort Collins, Colorado,” agreeing that a brewery and a landfarm six miles apart and connected by a pipeline constituted a single source).

220 See Letter from Richard R. Long, Dir., Air and Radiation Program, EPA Region 8, to Lee Ann Elsom, Envtl. Coordinator, Citation Oil & Gas Corp. (Dec. 9, 1999).

221 Memorandum from William L. Wehrum, EPA Acting Assistant Administrator, to EPA Regional Administrators, at 4–5 (Jan. 12, 2007) (Wehrum Memo) (discussing source determinations for oil and gas industries).

222 See Memorandum from Gina McCarthy, EPA Assistant Administrator, to EPA Regional Administrators, at 2 (Sept. 22, 2009) (McCarthy Memo) (discussing withdrawal of source determinations for oil and gas industries).

223 Compare id. at 1, with 45 Fed. Reg. at 52,694–95; see also Summit Petroleum Corp., 690 F.3d at 749 (“If the McCarthy Memorandum says anything about including supplemental and unexpected factors in the Title V stationary source analysis, it cautions against it.”).


natural gas wells with emissions from a compressor station.224 CDPHE had questioned EPA for adding a “functional interrelationship” prong, i.e., “interdependency,” to the traditional three-part test for aggregation.225 Moreover, CDPHE determined that aggregation is appropriate only when the two emissions sources have “exclusive interdependence.”226 EPA ruled in the CDPHE’s favor.227 WildEarth Guardians appealed EPA’s decision to the U.S. Court of Appeals for the Tenth Circuit, but the parties ultimately settled.228

[2] Florida River Compression Facility—Contiguous or Adjacent

In a ruling similar to the Frederick Compressor Station order, EPA Region 8 stated that, based on current EPA practice, it had to consider functional interrelationships when it considered whether two facilities on separate, noncontiguous properties are “adjacent.”229 But it minimized the importance of this “fourth prong” by focusing on the fact that the opera-tor’s central delivery point (CDP) and coalbed methane wells could supply gas to other companies’ facilities instead of just the operator’s process-ing facility.230 In other words, the facilities did not demonstrate “unique interdependence.”231 WildEarth Guardians appealed the permit issuance to EPA’s Environmental Appeals Board (EAB), but ultimately agreed to settle in exchange for Region 8 undertaking a pilot program designed to stream-line source determinations for upstream and midstream operations.232 The pilot program only applies to oil and gas projects for which EPA Region 8

224 See Order Denying Petition for Objection to Permit, In re Anadarko Petroleum Corp., Frederick Compressor Station, EPA Pet. No. VIII-2010-04 (EPA Adm’r Feb. 2, 2011).

225 See Response of CDPHE, Air Pollution Control Div., to Order Granting Petition for Objection to Permit at 8–23, 34–42 (July 14, 2010), In re Kerr-McGee/Anadarko Petroleum Corp., Frederick Compressor Station, EPA Pet. No. VIII-2008-02 (EPA Adm’r Oct. 8, 2009) (Response of CDPHE).

226 See id. at 20.227 Order Denying Petition, In re Anadarko Petroleum Co., supra note 224, at 2.228 See Settlement Agreement, WildEarth Guardians v. EPA, No. CAA 10-04 (EAB Oct.

20, 2011).229 See Letter from Callie A. Videtich, Dir., Air Program, EPA Region 8, to John D. Lowe,

Deputy Fla. Operations Manager, BP Am. Prod. Co., “Response to Comments,” at 10–11 (Oct. 18, 2010) (enclosing “Response to Comments”).

230 Id. at 9–13.231 Id. at 13.232 76 Fed. Reg. 71,027 (Nov. 16, 2011).

§ 6.06[4][a] Air Quality Regulations 6-37

is the primary permitting authority, and will last the shorter of two years or six permit actions.233

[3] Sims Mesa CDP—Common ControlIn April 2010, WildEarth Guardians objected to the issuance of a permit

by the New Mexico Environmental Department (NMED) for a gathering and compression facility.234 EPA granted the petition.235 Among other things, WildEarth Guardians alleged that NMED failed to adequately assess the common control prong for the CDP and adjacent wells.236 WildEarth Guardians alleged that the CDP operator had “indirect natural control” over the wells since the produced gas had to go to the CDP facility, even though a different company owned the wells.237 EPA did not necessarily agree, but directed NMED to make a more definitive factual record on the common control issue.238

[4] Other Aggregation Cases[a] Midwest—Contiguous or Adjacent

The oil and gas industry’s most significant aggregation victory to date may be the U.S. Court of Appeals for the Sixth Circuit’s recent ruling that the “contiguous or adjacent” prong of the three-part test unambiguously means that would-be aggregated facilities must have physical proximity, and therefore EPA cannot consider separate oil and gas activities to be “adjacent” merely because they are “functionally related.”239 In Summit Petroleum Corp., which arose in Michigan, an operator had gas wells in three sour natural gas fields, which in turn delivered all of the produced natural gas to a single sweetening plant that had no other sources of gas.240 EPA Region 5 determined that the wells, sweetening plant, and associated flares were “truly interdependent” and therefore “adjacent” for purposes

233 Settlement Agreement at exhibit A, WildEarth Guardians, No. CAA 10-04.234 Petition to Object to Issuance of a State Title V Operating Permit, In re Williams Four

Corners, LLC, Sims Mesa Central Delivery Point, EPA Pet. No. VI-2010-___ (EPA Adm’r filed Apr. 14, 2010).

235 Order Granting Petition for Objection to Permit, In re Williams Four Corners, LLC, Sims Mesa CDP Compressor Station, EPA Pet. No. VI-2011-__ (EPA Adm’r July 29, 2011).

236 Petition to Object, In re Williams Four Corners, LLC, supra note 234.237 Id. at 6.238 Order Granting Petition for Objection to Permit, In re Williams Four Corners, LLC,

supra note 235.239 Summit Petroleum Corp. v. EPA, 690 F.3d 733, 744–46 (6th Cir. 2012).240 Letter from Cheryl L. Newton, Dir., Air and Radiation Div., EPA Region 5, to Scott

Huber, Summit Petroleum Corp. (Oct. 18, 2010).

6-38 Mineral Law Institute § 6.06[4][b]

of aggregation, even though some wells were several miles from the plant. As a result, EPA directed the operator to obtain a permit.241 The operator appealed that source determination, and the court of appeals vacated the jurisdictional determination and remanded the case to EPA for a reassess-ment of the “contiguous or adjacent” factor in light of the proper, plain-meaning application of the requirement that the operator’s activities be aggregated only if they are located on physically contiguous or adjacent properties.242

[b] Marcellus ShaleIn 2011, the West Virginia Air Quality Board upheld the West Virginia

Department of Environmental Protection’s decision to issue two separate preconstruction permits for two separate compressor stations owned by the same company.243 Two cases are currently before the Pennsylvania Environmental Hearings Board. In one case, an environmental group has appealed the issuance of a permit to construct a compressor station.244 The appeal seeks aggregation of a compressor station’s emissions with 73 well sites on the basis of common control and proximity. The other case is an appeal of a permit to construct a fractionator tower and hot oil heater at an existing natural gas plant.245 The appeal focuses on whether any of the compressor stations owned and operated by the same company should be aggregated with the natural gas plant on the basis of functional interdepen-dence, i.e., the “fourth prong” of the aggregation test.

[5] Aggregation LessonsThe entire natural gas production, gathering, processing, and transpor-

tation system is connected via a network of pipes. For decades environ-mental agencies and environmental groups have defined aggregation in terms of connectedness. The Sixth Circuit’s opinion in Summit Petroleum Corp. strikes a heavy blow against this interpretation of the aggregation test. Several key distinguishing facts regarding oil and gas production seem to drive the cases in which aggregation was not found: (1) opera-tors drill wells where they find reserves, and construct support systems, such as processing and compression, based on delivery needs; (2) between

241 Id. at 7–8.242 Summit Petroleum Corp., 690 F.3d at 751.243 Final Order, Hughes v. Benedict, Appeal No. 10-03-AQB, at 2–3 (W. Va. Air Quality

Bd. Aug. 6, 2011). One of the authors participated in the cited case.244 Grp. Against Smog & Pollution v. Pa. Dep’t of Envtl. Prot., EHB Docket No. 2011-

065-R (Pa. Envtl. Hearing Bd. filed May 2, 2011).245 Clean Air Council v. Pa. Dep’t of Envtl. Prot., EHB Docket No. 2011-072-R (Pa. Envtl.

Hearing Bd. filed May 13, 2011).


well spacing requirements and surface use and engineering consider-ations, operators do not have wide discretion regarding where they locate upstream and midstream facilities; and (3) the complicated and changing business relationships and ownership structures, e.g., ownership interest in a well versus the gas stream versus the processing facility, differentiate the oil and gas industry from other industries. For all these reasons, operators do not choose the locations of upstream and midstream sites for the pur-pose of avoiding air quality requirements, or to define an emission source in one manner versus another.246

As always, operators must vigilantly monitor particular state guidance and rules in this rapidly changing area. Several states have developed their own guidance documents for aggregation, typically using a quarter-mile rule of thumb definition for “adjacent.”247 Operators can use this state guidance, the Summit Petroleum Corp. opinion, and the trend in recent Intermountain West cases toward requiring “exclusive interdependence” as the unwritten “fourth” prong of the aggregation analysis to reduce the impact of the industry’s inherent connectedness and refocus regulators on the three-prong test in the applicable regulations for determining when separate facilities comprise a single “stationary source.”

§ 6.07 EPA’s Indian Country Rules[1] The “Gap” in Indian Country Permitting

Until 2011, no minor source permitting regulations applied through-out Indian country, where extensive oil, natural gas, and other resource development occurs.248 As discussed in § 6.02[3], above, many states have “minor source” and “synthetic minor source” permit programs. These programs play a critical role in allowing sources to avoid rigorous “major source” regulatory programs through the use of synthetic minor limits. However, Indian country has not historically fallen within state jurisdic-tion.249 This seriously impaired the ability of operators to avoid major

246 See Response of CDPHE, supra note 225, at 4–8.247 See, e.g., Okla. Dep’t of Envtl. Quality, “Permitting Collocated Facilities,” at 3 (Feb. 9,

2012); Pa. Dep’t of Envtl. Prot., “Guidance for Performing Single Stationary Source Deter-minations for Oil and Gas Industries,” at 6–8 (Oct. 6, 2012); Tex. Comm’n on Envtl. Quality, “Definition of Site Guidance,” at 1 (Aug. 2010); La. Dep’t of Envtl. Quality, “Interpreta-tion of Contiguous for Oil & Gas Production Facilities,” http://www.deq.state.la.us/portal/tabid/2347/Default.aspx.

248 76 Fed. Reg. 38,748, 38,749 n.1 (July 1, 2011).249 Id. at 38,752 n.9 (citing 18 U.S.C. § 1151; Alaska v. Native Vill. of Venetie Tribal Gov’t,

522 U.S. 520, 527 n.1 (1998); California v. Cabazon Band of Mission Indians, 480 U.S. 202 (1987); HRI v. EPA, 198 F.3d 1224 (10th Cir. 2000)). EPA has approved only a handful of tribal minor NSR programs. Sources located within the exterior boundaries of Indian

6-40 Mineral Law Institute § 6.07[1][a]

permitting programs, which a comparable source located on land subject to state jurisdiction with the same emissions often could do.250 This gap placed tribes at an economic disadvantage since operators had an incentive to site facilities elsewhere. It also imposed undue burdens on sources.251 While tribes have the authority to develop Tribal Implementation Plans to regulate air sources,252 very few have chosen to do so.253 As a result, many sources in Indian country, which might have otherwise qualified as syn-thetic minor sources, could not avoid MACT, Title V, and PSD. In addition, EPA had no power to regulate “true minor sources,” leaving many facilities essentially unregulated.254

After years of delay, EPA promulgated new rules in 2011 to address this permitting gap.255 EPA did so by creating two basic programs: an Indian country minor source program and an Indian country Nonattainment NSR program.

[a] Indian Country Minor Source ProgramNew and modified sources exceeding certain emission thresholds must

at least obtain minor source preconstruction permits.256 Operators can use the minor source permits to adopt controls and keep emissions below levels that would trigger other major source programs.257 Under the minor source program, operators must obtain either site-specific permits with case-by-case determinations of emission limits and control requirements, general permits, or synthetic minor permits. The site-specific minor source permits will contain emission limitations, monitoring, record-keeping, and reporting requirements.258 EPA will develop emission limita-tions based on a case-by-case review of local air quality conditions, typical

reservations in Idaho, Oregon, and Washington could apply for synthetic minor status under the implementation programs applicable to those reservations until the new “Tribal NSR” rule became effective. Id. at 38,749 n.1 (citing 40 C.F.R. § 49.139 & pt. 49, subpt. M).

250 See id. at 38,750.251 See, e.g., id. at 38,761–62.252 42 U.S.C. §§ 7410(o), 7601(d); see also Order Denying Petition for Review, Peabody

W. Coal Co., CAA Appeal No. 11-01, 15 E.A.D. ___, at 4 (EPA Envtl. Appeals Bd. Mar. 13, 2012) (citing 42 U.S.C. § 7601(d)(1); 40 C.F.R. pt. 49).

253 76 Fed. Reg. at 38,753.254 Id. at 38,756.255 Id. at 38,748.256 Id. at 38,761.257 Id. at 38,760.258 40 C.F.R. § 49.155.


control technology or other emissions reduction measures used by similar sources in surrounding areas, anticipated economic growth in the area, and cost-effective emission reduction alternatives.259 Moreover, if EPA or a delegated tribal permitting agency becomes concerned that a proposed new or modified minor source would cause or contribute to a NAAQS or PSD increment violation, then such permitting agency can require an Air Quality Impacts Analysis (AQIA).260 The AQIA requirement may slow oil and gas development in potential nonattainment areas, such as the Uintah Basin and Fort Berthold Reservation.

[b] Indian Country Nonattainment NSR ProgramEPA also established a major source preconstruction permitting pro-

gram for nonattainment areas in Indian country.261 The Indian country Nonattainment NSR program would apply should an Indian country area, such as the Uintah Basin or Fort Berthold Indian Reservation in North Dakota, fall into nonattainment for ozone.

New or modified sources in nonattainment areas of Indian country that have PTE at or above major NSR thresholds must apply for and receive a Nonattainment NSR permit before commencing construction.262 Require-ments under the new rule include installing stringent emissions controls, obtaining emissions offsets, certifying compliance of other sources, and providing an analysis of alternative sites, sizes, production processes, and environmental control techniques.263

[2] Key Time FramesExisting true minor sources, i.e., those that do not need synthetic minor

limits to avoid major source status, must register with EPA by March 1,

259 Id. § 49.154(c)(1). The resulting control technology requirements may range from no controls, to control technology that is less stringent than the reasonably available con-trol technology (RACT), to BACT-level controls. See 76 Fed. Reg. at 38,760. Moreover, the resulting permit limits may include numeric limits on the quantity, rate, or concentration of emissions; pollution prevention techniques; design, equipment standards, work practice, or operational standards; or some combination thereof. 40 C.F.R. § 49.154(c)(3). However, the new program requires numeric emission limits when such limits are technically and economically feasible. Id. § 49.154(c)(2).

260 40 C.F.R. § 49.154(d). An AQIA will require use of the air dispersion models and pro-cedures of id. pt. 51, app. W. If the AQIA shows that the proposed minor source or modifi-cation would cause or contribute to a NAAQS or PSD increment violation, the source must reduce or mitigate such impacts before it may receive a permit. Id. § 49.154(d)(3).

261 76 Fed. Reg. at 38,748.262 40 C.F.R. § 49.166(c)(1), (d)(1).263 Id. § 49.169(b).


2013.264 New true minor sources must do so within 90 days of beginning operation.265 The minor source preconstruction permitting program will begin applying to new construction of and changes to true minor sources six months after a general permit is issued for the source type, or Septem-ber 2, 2014, whichever is earlier.266 Thus, true minor sources can avoid the minor source permitting requirement if they are constructed before September 2, 2014, or they can comply with a general permit.267 Special applicability rules and various time frames apply to sources that already have synthetic minor treatment through some other mechanism or poli-cy.268 Sources that exceed “major source” permitting thresholds and that seek to limit emissions below such thresholds can do so now.269

[3] Implementation: Permitting, Public Comment, and Review

The new Indian country permitting rules will likely have a substantial impact on oil and gas operations.270 They have features that appear in state preconstruction permit programs, such as case-by-case review of control technology, air quality impact analysis, monitoring, record-keeping, and reporting by the source owner or operator, public participation through public notice and comment requirements, and administrative and judicial review upon a permit appeal.271 However, stakeholders have criticized some of these provisions as lacking the sort of flexibility and streamlining that is apparent in many state permitting programs, especially in relation to oil and gas development activities.272

EPA has struggled to implement the new rules.273 For example, shortly after promulgating the rules, EPA entered into “consent agreements” with operators in the Bakken Formation of North Dakota, which is partially

264 76 Fed. Reg. at 38,784.265 Id.266 Id.267 See id.268 Id. at 38,783–84.269 Id. at 38,783.270 See Gribovicz, supra note 78, at 4; see also 76 Fed. Reg. at 38,749.271 76 Fed. Reg. at 38,771, 38,761, 38,764–65.272 See id. at 38,773–74 (discussing tribal representatives’ concerns).273 See generally 77 Fed. Reg. 48,878 (Aug. 15, 2012).


located beneath an Indian reservation.274 These consent agreements accommodated the “unique situation” of producers in the Bakken who needed Indian country minor source permits to avoid violation of the CAA when the Indian country rule became effective on August 30, 2011.275 At the time, EPA lacked sufficient information to develop permits, and it took until March 2012 to issue the first batch of draft permits.276 However, as a result of the new applicability provisions in the Indian country programs, EPA faced a task of developing and finalizing permits for more than 600 oil and gas production facilities.277 EPA tried to issue the permits before the consent agreements expired, but realized it could not do so. As a result, it promulgated a stop-gap, interim rule imposing emissions limits and requiring controls for certain oil and gas facilities on the Fort Berthold Reservation until EPA can come up with another solution.278

The new Indian country programs also allow for public review of per-mits, which can further delay oil and gas development.279 Before issuing a permit under either program, EPA or the delegated permitting agency must provide a period of at least 30 days from the date of the public notice for comments and for requests for a public hearing.280 EPA has published permit application forms,281 and has subjected several synthetic minor source NSR permits for oil and gas operations on the Fort Berthold Indian Reservation in North Dakota to public comment.282 However, the pace of application processing suggests that EPA may lack sufficient resources to timely issue permits. In fact, EPA has not issued any such permits, and may now intend to abandon its permitting framework in favor of interim final rules that take the form of general permits.

Moreover, the potential for appeal may further slow oil and gas devel-opment. After EPA or the delegated permitting agency issues a permit,

274 E.g., Administrative Complaint and Consent Agreement, In re Enerplus Res. Corp., EPA Region 8 Docket No. CAA-08-2011-0021 (Aug. 29, 2011).

275 See id. ¶¶ A.7, B.1–.2.276 77 Fed. Reg. at 48,880.277 Id. at 48,881.278 See id. The new rule is discussed further in § 6.07[4], infra.279 40 C.F.R. §§ 49.157, .171.280 Id. §§ 49.157(b)(2)(ix), .171(b)(2)(viii).281 EPA Region 8, “Tribal Minor New Source Review Permitting,” http://www.epa.gov/

region8/air/permitting/tmnsr.html.282 See EPA Region 8, “Air Permit Public Comment Opportunities,” http://www.epa.gov/

region8/air/permitting/pubcomment.html.


any person who filed comments on the draft permit or participated in the public hearing has 30 days to petition the EAB to review any condition of the permit decision.283 If a challenger files a petition for review, then the permits will be stayed pending EAB review.284 EAB review can take several months or a year, and might even result in EAB remanding to the permitting agency for additional consideration and, accordingly, further delays.285 After EAB issues its decision, the challenger may then seek judi-cial review in federal court.286 So, there is a potential for challengers to use the new Indian country permitting programs to delay development, even where the proposed oil and gas activities would only require minor source permits.

[4] Fort Berthold Indian ReservationOn August 15, 2012, EPA published a temporary, reservation-specific

Federal Implementation Plan (FIP) to regulate emissions from oil and gas production facilities on the Fort Berthold Indian Reservation.287 The new rule specifically targets VOC emissions from operations on the Fort Ber-thold Reservation from flowback, heater/treaters, and storage tanks associ-ated with production from oil and gas wells from the Bakken, Three Forks, and Sanish formations.288 It is not a permitting program per se, but it does provide a basis for calculating PTE below major source thresholds while, in return, requiring operators to conduct “green completions” or route cas-inghead gas from oil and gas wells to a flare achieving 90% reduction, and to recover or achieve 98% emissions reduction from produced gas during separation and storage operations.289 The interim rule became effective, with actual notice by EPA to operators and owners, beginning August 3, 2012, for enforcement purposes.290

283 40 C.F.R. §§ 49.159(d)(2), .172(d)(2).284 Id. §§ 49.159(a)(2), .172(a)(2).285 See id. §§ 49.159(d)(8)(iii), .172(d)(8)(iii).286 Id. §§ 49.159(d)(8), .172(d)(8).287 77 Fed. Reg. 48,878, 48,893–98 (Aug. 15, 2012) (to be codified at 40 C.F.R.

§§ 49.140–.147).288 Id. at 48,893–94 (to be codified at 40 C.F.R. §§ 49.140, .142(a)). The rule applies to oil

and gas facilities producing from these formations (the “Bakken Pool”) that are construct-ing and operating on the Reservation in North Dakota on or after August 12, 2007. Id. at 48,887.

289 Id. at 48,884–85, 48,888–89 (to be codified at 40 C.F.R. § 49.143).290 Id. at 48,879.


§ 6.08 Greenhouse Gas Regulation[1] Tailoring Rule

In 2007, the U.S. Supreme Court decided that greenhouse gases are “air pollutants” as that term is used in the CAA.291 After taking several regulatory steps,292 EPA promulgated the “Greenhouse Gas Tailoring Rule” to regulate emissions of greenhouse gases through preconstruction and operating permits.293 On June 26, 2012, the U.S. Court of Appeals for the District of Columbia Circuit upheld EPA’s rules relating to emissions of greenhouse gases from stationary sources.294 The court’s decision to uphold EPA’s various greenhouse gas rulemakings may ultimately impact operators nationwide.295

Oil and gas upstream activities, such as exploration and production facil-ities consisting of several wells and associated separators and storage tanks, may emit greenhouse gases at levels in excess of the permitting thresh-olds.296 EPA has proposed a “synthetic minor” program for greenhouse

291 Massachusetts v. EPA, 549 U.S. 497 (2007).292 75 Fed. Reg. 25,324 (May 7, 2010) (adopting rules that require a reduction in emis-

sions of greenhouse gases from motor vehicles); 74 Fed. Reg. 66,496 (Dec. 15, 2009) (find-ing that emissions of carbon dioxide (CO2), methane (CH4), and several other greenhouse gases present an endangerment to public health and the environment).

293 75 Fed. Reg. 31,514 (June 3, 2010). The Tailoring Rule has a multistep phase-in for greenhouse gas permitting. In “Step One,” which became effective on January 2, 2011, EPA applied PSD and Title V requirements only to sources that were already subject to PSD or Title V due to their non-greenhouse gas pollutants. Id. at 31,516. In “Step Two,” which became effective on July 1, 2011, EPA phased in additional large sources of greenhouse gas emissions. Id.

294 Coal. for Responsible Regulation v. EPA, 684 F.3d 102 (D.C. Cir. 2012) (consolidating and dismissing various challenges to the Timing and Tailoring Rules for lack of standing because petitioners have not suffered injuries-in-fact).

295 The result may be particularly challenging for operators in states, such as Texas and Wyoming, that have a dual-permitting permitting scheme in which the state environmental agency issues PSD permits for historically regulated pollutants, but EPA issues PSD permits for greenhouse gases. EPA published a FIP making EPA the greenhouse gas PSD permit-ting authority for states, including Wyoming, that did not have the authority under their state laws (i.e., in their SIPs) to implement PSD permitting for greenhouse gases. 75 Fed. Reg. 82,246, 82,254 (Dec. 30, 2010). Similarly, EPA published a FIP making EPA Region 6 the PSD permitting authority for greenhouse gases in Texas. 76 Fed. Reg. 25,178, 25,209 (May 3, 2011). Both states sued EPA. Util. Air Regulatory Grp. v. EPA, No. 11-1037 (D.C. Cir. filed Feb. 11, 2011); Texas v. EPA, No. 10-1425 (D.C. Cir. filed Dec. 30, 2010); see also Gabriel Nelson, “Wyo. Joins Texas in Suing EPA Over Rollout of Greenhouse Gas Regula-tions,” N.Y. Times, Feb. 16, 2011.

296 E.g., Letter from Callie A. Videtich, Acting Assistant Regional Administrator, Office of Partnerships and Regulatory Assistance, EPA Region 8, to A. Dewey Cooper, HES Pro-fessional, Bakken Operations, at Encl. 4-5 (Apr. 19, 2012).


gas emissions for dual-permitting states.297 However, EPA tabled the syn-thetic minor permit proposal on the grounds that the program “may not be needed at this time.”298 EPA’s decision is undermined by the fact that EPA has given itself the authority to issue synthetic minor source permits in Indian country,299 and several operators have applied to take advantage of that permit option.300 Accordingly, EPA can issue synthetic minor source permits for greenhouse gas emissions associated with oil and gas activities in Indian country, for example, the Bakken Formation underlying the Fort Berthold Reservation,301 but apparently cannot and will not issue the same activities in a dual-permitting state such as Wyoming.

[2] Greenhouse Gas BACT for Oil and GasEPA’s greenhouse gas rules may place operators of certain emissions

sources, such as large natural gas processing facilities, in a position of hav-ing to review available determinations of what constitutes BACT for green-house gas sources under the applicable PSD program. EPA will apply its own guidance document for PSD permitting and BACT determinations.302 For example, EPA generally will not require a PSD permit applicant to model or conduct ambient monitoring for greenhouse gases at this time, because EPA has not yet promulgated NAAQS for greenhouse gases.303 For BACT, EPA will likely require consideration of various options, such as

297 77 Fed. Reg. 14,226, 14,228 (Mar. 8, 2012). This would allow operators in those states, such as Texas and Wyoming, to install controls reducing greenhouse gas emissions to levels below the major source thresholds, thereby avoiding the stringent major source precon-struction permitting process.

298 77 Fed. Reg. 41,051, 41,055–56 (July 12, 2012). Later in the preamble to “Step Three” of the Tailoring Rule, EPA acknowledges that a primary reason for the delay is EPA’s own underestimation of the administrative burden associated with synthetic minor source per-mitting. E.g., id. at 41,057, 41,066–67.

299 40 C.F.R. § 49.158.300 E.g., Draft Air Pollution Control Proposed Permit #SMNSR-TAT-000206-2011.001,

Marathon Oil Company, Danks Well Pad Oil & Gas Production Facility, Fort Berthold Indian Reservation, McKenzie County, North Dakota, at 6 (Marathon Oil Proposed Per-mit), http://www.epa.gov/region8/air/permitting/MarathonDanksSMNSRDraftPermit.pdf; see also EPA Region 8, “Air Permit Public Comment Opportunities,” http://www.epa.gov/region8/air/permitting/pubcomment.html.

301 See Marathon Oil Proposed Permit, supra note 300.302 EPA, Office of Air Quality Planning and Standards, “PSD and Title V Permitting

Guidance for Greenhouse Gases,” at 17–46 (Mar. 2011).303 Id. at 47–48.


energy efficiency, fuel-switching, and utilization of greenhouse gases for enhanced oil and gas recovery projects.304

[3] Mandatory Reporting RuleIn 2010, EPA also adopted rules requiring the annual reporting of green-

house gas emissions from onshore oil and gas production facilities.305 The Mandatory Reporting Rule (MRR) requires petroleum and natural gas facilities that emit 25,000 metric tons or more of carbon dioxide equivalent (CO2e) per year to report annual methane (CH4) and carbon dioxide (CO2) emissions from equipment leaks and venting, and emissions of CO2, CH4, and nitrous oxide (N2O) from gas flaring and from onshore petroleum and natural gas emissions sources.306 Stakeholders have recently questioned the research supporting EPA’s estimates of emissions from upstream natu-ral gas production.307 In light of the combined Tailoring Rule, MRR, and regulation of methane as a surrogate for VOC, EPA appears to be building a framework for direct regulation of methane emissions from oil and gas operations.308

§ 6.09 Land Management Decisions and the National Environmental Policy Act[1] Air Quality Mitigation in NEPA Documents

NEPA, which is ostensibly a procedural statute only, requires federal agencies to conduct a review process that often results in substantive requirements and restrictions on oil and gas development in relation to air quality.309 In a recent case, for example, an operator could only obtain

304 Id. at 21–22, 27, 42–43.305 75 Fed. Reg. 74,458 (Nov. 30, 2010).306 Id. at 74,490.307 See American Petroleum Inst. & America’s Natural Gas Alliance, “Characterizing Piv-

otal Sources of Methane Emissions from Unconventional Natural Gas Production” (Final Report, June 1, 2012).

308 Cf. EPA, Office of Air Quality Planning and Standards, “Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews, 40 CFR Parts 60 and 63, Response to Public Comments on Proposed Rule August 23, 2011 (76 FR 52738),” at 415–16, 419–20 (2012) (responding to comments on the newly promulgated NSPS OOOO alleging that EPA’s requirement to measure natural gas emissions as a surrogate for VOC emissions is actually direct, unauthorized regulation of methane, i.e., greenhouse gases).

309 E.g., 42 U.S.C. § 4332(2)(C). Section 102 of NEPA requires that federal agencies “to the fullest extent possible” prepare an environmental impact statement (EIS) for every major federal action significantly affecting the quality of the human environment. An agency’s analysis of environmental impacts must amount to a detailed statement indicating that the agency took a “hard look” at all of the potentially significant environmental consequences of the proposed action considering all relevant matters of environmental concern.


approval of a large natural gas development project by agreeing to imple-ment specific air quality-related restrictions.310 In another case, an opera-tor proposed in 2006 to expand its operations in the Uintah Basin by drilling more than 1,000 new wells through the year 2020.311 EPA criticized the proposal, citing wintertime ozone concerns.312 Six years after the pro-posal, the Bureau of Land Management (BLM) at last issued a final envi-ronmental impact statement (EIS) with air quality mitigation measures.313 Nonetheless, the project is still subject to opposition.314 The likelihood that a challenger may obtain relief will depend heavily on the strength of the challenger’s arguments that the federal agency did not adequately fol-low the procedures that govern its review of the environmental impacts or other wise did not comply with applicable law. In other words, NEPA guards against uninformed agency action rather than unwise agency action.315 This can be a difficult burden for a challenger to bear. However, challenges to federal oil and gas development can cause lengthy, expensive delays for proposed projects.316

[2] Formalizing Air Quality Review and DataThe land management agencies are busy on the air quality front. In

June 2011, several agencies entered into a memorandum of understanding (MOU) to collaborate on analyzing air quality impacts during the NEPA review process.317 Similarly, in 2010, the Council on Environmental Qual-ity issued draft guidance to the land management agencies describing how

310 See BLM, “Greater Natural Buttes Final Environmental Impact Statement,” vol. II, app. A (Mar. 2012) (listing air quality mitigation measures imposed by BLM).

311 BLM, “Gasco’s Uintah Basin Natural Gas Development Project Environmental Impact Statement Scoping Notice” (Feb. 10, 2006), http://www.blm.gov/ut/st/en/info/newsroom/2006/02/gasco_s_uintah_basin.html.

312 BLM, “Supplemental Air Quality Review Provides Path Forward for Major Utah Gas Development Project” (June 9, 2011), http://www.blm.gov/wo/st/en/info/newsroom/2011/june/NR_06_09_2011.html.

313 BLM, “Final Environmental Impact Statement, Gasco Uinta Basin Natural Gas Proj-ect” (Mar. 2012).

314 W. King Grant, “Gasco Defends Project,” Salt Lake Tribune, Apr. 19, 2012.315 Robertson v. Methow Valley Citizens Council, 490 U.S. 332, 351 (1989).316 See Western Energy Alliance, supra note 83, at 13–14, 17–18, 22, 25–27.317 MOU among the U.S. Dep’t of Agric., U.S. Dep’t of the Interior, and EPA, Regarding

Air Quality Analyses and Mitigation for Federal Oil and Gas Decisions through the Nat’l Envtl. Policy Act Process (June 23, 2011) (EPA NEPA MOU).


they should address climate change in their NEPA decision documents.318 Meanwhile, BLM offices are drafting air quality resources documents for Applications for Permit to Drill.319 The federal permitting activity takes place against the backdrop of a CAA requirement that every oil and gas action triggering NEPA must comply with the applicable SIP for the state in which it is located.320

NEPA plays a significant role in the pace of oil and gas development.321 Operators have to justify the substantive measures that they are taking to protect air quality even though NEPA is a procedural statute. Several recent administrative and civil cases dealing with oil and gas development projects provide guidance and stand for the following propositions. First, the land management agencies review the CAA separately from EPA and state agencies.322 The courts will affirm the agencies’ decisions regarding the methodology and scope of air quality review as long as the agencies documented their deliberations in the administrative record.323 Moreover, the courts will defer to the agencies’ determinations that certain air quality analyses are too complex,324 and will require challengers to present mean-ingful, feasible alternatives.325 Accordingly, courts will defer to agency approvals of oil and gas development if the agencies document their con-

318 Memorandum from Nancy H. Sutley, Chair, Council on Envtl. Quality, to the Heads of Fed. Dep’ts & Agencies, “Draft Guidance for NEPA Mitigation and Monitoring,” at 1 (Feb. 18, 2010).

319 See, e.g., BLM, N.M. State Office, “Air Resources Technical Report for Oil and Gas Development” (Nov. 2011).

320 42 U.S.C. § 7506(c); accord Dep’t of Energy, Environment, Safety and Health, Office of NEPA Policy and Assistance, “Clean Air Act General Conformity Requirements and the National Environmental Policy Act Process,” at 1 (Apr. 2000).

321 See Western Energy Alliance, supra note 83, at 13–14, 17–18, 22, 25–27.322 See generally Wyo. Outdoor Council, 176 IBLA 15, GFS(O&G) 15(2008) (Jonah Infill

Project litigation); see also Biodiversity Conservation Alliance v. BLM, No. 09-cv-08-J, 2010 WL 3209444 (D. Wyo. June 10, 2010) (unreported) (affirming IBLA order and recognizing that much of the IBLA opinion was directed toward review of air quality issues), appeal dismissed, 438 F. App’x 669 (10th Cir. 2011).

323 San Juan Citizens Alliance v. Stiles, 654 F.3d 1038, 1057 (10th Cir. 2011) (deferring to the U.S. Forest Service’s decision to set the analytical boundary for assessing air quality impacts so as to coincide with state borders in lieu of other area features); Theodore Roose-velt Conservation P’ship v. Salazar, 616 F.3d 497, 509–10, 513 (D.C. Cir. 2010) (Atlantic Rim litigation) (deferring to the BLM’s use of a model for analyzing air quality impacts although the model had subsequently become obsolete).

324 NRDC v. Vilsack, No. 08-CV-2371-CMA, 2011 WL 3471011, at *7 (D. Colo. Aug. 5, 2011) (Hell’s Gulch litigation).

325 WildEarth Guardians v. Forest Service, 828 F. Supp. 2d 1223, 1240 (D. Colo. 2011) (West Elk Mine litigation).


sideration of various options available to the agencies at the time, and will not overturn agency approvals based on the mere existence of competing, subsequently introduced options that may undermine those approvals.326 However, the courts will vacate the agencies’ approvals of oil and gas devel-opment if the agencies do not explain the limitations on their analysis in the administrative record.327 Accordingly, operators can improve the odds of surviving litigation by taking protective steps, such as engaging federal and state permitting agencies early, modeling impacts, and making sure the agencies memorialize those steps in the administrative record.

[3] NEPA Case Study: Hell’s Gulch, White River National Forest, Colorado

A recent case arising out of western Colorado serves as a good example of the interaction between the CAA, NEPA, and other federal environmen-tal statutes, as well as the interaction between the various state and federal agencies that might weigh in on an oil and gas project in the Intermountain West. In 2005, an oil and gas company proposed a development plan for a natural gas development project in Mesa County, Colorado, in the White River National Forest.328 In 2008, the U.S. Forest Service (Forest Service) and BLM approved the drilling of up to 45 natural gas wells, the construc-tion of six well pads, the creation of six miles of new access roads, and a total of approximately 50 acres of new surface disturbance.329

Two environmental groups appealed the approval, alleging that the federal agencies’ actions violated NEPA, the National Forest Management Act of 1976 (NFMA),330 and the Federal Land Policy and Management Act of 1976 (FLPMA)331 because they validated CAA ozone standard

326 Amigos Bravos v. BLM, No. 6:09-cv-00037-RB-LFG, 2011 WL 7701433, at *32 (“Courts are not in a position to decide the propriety of competing methodologies . . . but instead, should determine simply whether the challenged method had a rational basis and took into consideration the relevant factors.” (quoting Comm. to Preserve Boomer Lake Park v. Dep’t of Transp., 4 F.3d 1543, 1553 (10th Cir. 1993))).

327 Colo. Envtl. Coal. v. Salazar, No. 08-cv-01460-MSK-KLM, 2012 WL 2370067, at *17 (D. Colo. June 22, 2012) (Roan Plateau litigation).

328 NRDC, 2011 WL 3471011, at *1. The project included construction of up to seven well pads, almost eight miles of access roads and gathering pipelines, and up to 52 natural gas wells. U.S. Dep’t of Agric., Forest Serv., “Environmental Assessment: Plains Exploration and Production Company, Hells Gulch North, Phase 2,” at 1 (May 2008).

329 NRDC, 2011 WL 3471011, at *2.330 16 U.S.C. §§ 472a, 521b, 1600, 1611–1614.331 43 U.S.C. §§ 1701–1782.


violations.332 As required by NEPA, the court limited its review to whether the agencies took a “hard look” at the environmental consequences, not whether the agencies had ensured the protection of air quality.333 The For-est Service did not undertake a quantitative analysis specifically examining ozone in the environmental assessment, but it did model project-level and cumulative analysis of NOx and estimate the project’s effects on VOC emis-sions.334 The Forest Service could have conducted more extensive regional ozone modeling.335 However, the court declined to direct the Forest Ser-vice to engage in any particular scientific investigation or to utilize any particular technology in its NEPA analysis.336

The court also ruled in favor of the agencies on the other CAA-related claims. Notably, the environmental groups argued that the project would violate visibility standards. The court did not resolve the parties’ dispute over whether the PSD program required the Forest Service to protect visi-bility.337 However, the court found it important that the Forest Service had conducted visibility analyses and discussed a plan for interagency coop-eration with the CDPHE’s Air Pollution Control Division to mitigate air quality effects on places like the national parks.338 The Forest Service did enough to satisfy the court.

332 See id. at *6 n.13 (“NFMA governs Forest Service decisions regarding surface use of National Forest lands, whereas FLPMA governs BLM decisions regarding subsurface use of National Forest lands.”).

333 Id. at *7–10.334 Id. at *9; see also San Juan Citizens Alliance v. Stiles, No. 08-cv-00144-RPM, 2010

WL 1780816, at *20 (D. Colo. May 3, 2010) (deferring to the Forest Service’s determination that insufficient VOCs would be emitted from proposed coalbed methane production and processing to result in significant ozone formation), aff ’d in part and remanded in part on other grounds, 654 F.3d 1038 (10th Cir. 2011).

335 See NRDC, 2011 WL 3471011, at *9.336 Id. The court further explained this point, “It certainly appears that quantitative ozone

modeling would have been the most effective way to ensure . . . compliance with the ozone NAAQS. However, the Court is not in a position to conclude . . . that the Forest Service’s methodology was insufficient in terms of determining compliance with NAAQS.” Id.

337 Id. at *11; see also San Juan Citizens Alliance, 654 F.3d at 1057 (explaining that iden-tifying the geographic boundaries in which cumulative effects will be measured for the purpose of visibility analysis is committed to agency discretion); cf. Amigos Bravos v. BLM, No. 6:09-cv-0037-RB-LFG, 2011 WL 7701433, at *13 (“This does not mean the agency can forego all air quality analysis at the leasing stage. BLM did not, however, ignore the ozone issue. BLM looked at air quality modeling.”).

338 NRDC, 2011 WL 3471011, at *11.


§ 6.10 Modeling[1] Permitting

Air quality emissions modeling plays an important part in each of the topics discussed above. Air permit applications for an oil and gas develop-ment project increasingly require a demonstration that the project emis-sions will not impair ambient air quality standards.339 In most cases, this determination requires air dispersion modeling.340 Dispersion models are the primary tools used in the air quality analysis.341 These models use inputs regarding a proposed project’s impact area; emissions sources, including equipment locations, emission rates, and stack heights; background air emissions inventory data; and meteorological data in order to estimate the ambient concentrations that will result from a permit applicant’s proposed emissions in combination with emissions from existing sources.342 “The estimated total concentrations are used to demonstrate compliance with any applicable NAAQS or PSD increments.”343 The required models have become increasingly complex, and stringent air quality standards have made it more difficult to achieve modeled results that show attainment of standards.344 Accordingly, operators should consider consulting with the applicable permitting agency to determine the particular requirements for the modeling analysis to assure acceptability of any air quality modeling techniques used to perform the air quality analysis contained in a permit application.

[2] One-Hour NO2 and SO2 NAAQSIn 2010, EPA promulgated final rules adopting new, one-hour pri-

mary NAAQS for NO2 and SO2.345 These revisions and accompanying

339 E.g., EPA NEPA MOU, supra note 317, at 1–2, 10; Wyo. Dep’t of Envtl. Quality, “Interim Policy on Demonstration of Compliance with WAQSR Chapter 6, Section 2(c)(ii) for Sources in Sublette County,” at 1-2 (July 21, 2008).

340 N.M. Air Quality Bureau, “Air Dispersion Modeling Guidelines,” at 8 (rev. July 29, 2011).

341 EPA, “New Source Review Workshop Manual, Prevention of Significant Deteriora-tion and Nonattainment Area Permitting,” at C.24 (draft Oct. 1990).

342 Id. at C.26–C.50.343 Id. at C.24.344 See, e.g., 70 Fed. Reg. 68,218 (Nov. 9, 2005).345 75 Fed. Reg. 35,520 (June 22, 2010) (SO2); 75 Fed. Reg. 6474 (Feb. 9, 2010) (NO2).

EPA set the new one-hour NO2 standard at 100 ppb, and the new one-hour SO2 standard at 75 ppb. At least one study has questioned the conclusion that there is a causal relationship between an increase in ambient concentrations of NO2 and an increase in health effects. See Julie E. Goodman et al., “Meta-Analysis of Nitrogen Dioxide Exposure and Airway Hyper-Responsiveness in Asthmatics,” 39 Crit. Rev. Toxicology 719 (2009). However, the U.S. Court


guidance346 may have dramatic effects on NSR permitting for new and modified oil and gas facilities. Several factors have proven to make it difficult for oil and gas operators to demonstrate compliance with these new one-hour NAAQS. Primarily, the new NAAQS are more stringent, and the shortened one-hour measurement period makes it far more likely that a fence-line receptor will record a pollutant concentration exceeding the new standard.347 Accordingly, emissions from operations that would not have caused concern under a longer, area-wide averaging period can now result in permitting delays, more stringent permitted emissions limits, operational limitations, and requirements for emission controls.348 Emis-sions from RICE and flares may cause problems, especially if operators move such equipment closer to the fence line or move the property bound-ary closer to them.349 Even relatively small emission increases associated with new or modified sources or changes to property boundaries that bring fence-line receptors closer to emission sources can trigger additional modeling requirements and permitting delays.

of Appeals for the D.C. Circuit recently denied petitions to review the new standard. Am. Petroleum Inst. v. EPA, 684 F.3d 1342 (D.C. Cir. 2012). The D.C. Circuit also recently dis-missed challenges to the new one-hour SO2 standard and concluded that EPA did not act arbitrarily in setting the standard. Nat’l Envtl. Dev. Ass’ns Clean Air Project v. EPA, 686 F.3d 803 (D.C. Cir. 2012).

346 Memorandum from Tyler Fox, Leader, Air Quality Modeling Group, EPA Office of Air Quality Planning and Standards, to EPA Regional Air Division Directors, “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-Hour NO2 National Ambient Air Quality Standard” (Mar. 1, 2011); Memorandum from Stephen D. Page, Director, EPA Office of Air Quality Planning and Standards, to EPA Regional Air Division Directors, “Guidance Concerning the Implementation of the 1-Hour SO2 NAAQS for the Prevention of Significant Deterioration Program” (Aug. 23, 2010); Memorandum from Stephen D. Page, Director, EPA Office of Air Quality Planning and Standards, to EPA Regional Air Division Directors, “Guidance Concerning the Implementation of the 1-Hour NO2 NAAQS for the Prevention of Significant Deterioration Program” (June 29, 2010); see also Memorandum from Kirsten King & Roland C. Hea, Colo. Dep’t of Pub. Health and Env’t, to Stationary Sources Staff, Local Agencies, Regulated Community (Sept. 20, 2010).

347 In 1971, EPA established primary NAAQS for NO2 of 53 ppb as an annual average in any given area. The NAAQS focused specifically on NO2 as an indicator for the broader category of NOx. Am. Petroleum Inst., 684 F.3d at 1345–46.

348 EPA reviewed a hypothetical area-wide standard as well as a peak standard. Id. at 1352. Under the proposed area-wide standard, the average value recorded by fence-line receptors in a given area had to meet the NAAQS, so that some receptors could record concentrations of NO2 above and some below the NAAQS. However, EPA adopted a peak standard that requires all monitors in an area to be below the 100 ppb level. Id. The peak standard set at 100 ppb roughly equates to an area-wide one-hour average concentration of 50–75 ppb. 75 Fed. Reg. 6474, 6494 (Feb. 9, 2010).

349 See Jennifer M. Geran, “Effects of the New NO2 and SO2 NAAQS Air Dispersion Modeling Requirements on the Oil and Gas Industry,” Air & Waste Mgmt. Ass’n Paper No. 2012-A-563-AWMA, at 19 (June 2012).


EPA’s guidance has also caused concerns regarding whether to use actual emissions or PTE, and whether companies can exclude intermittent emis-sions sources, such as emergency generators, from their modeling.350 The likelihood that topography, wind and atmospheric patterns, and unknown background ambient pollutant concentrations will heavily impact model-ing given the shortened one-hour averaging time compounds the com-plexity. Accordingly, operators should anticipate delays in permitting and challenges from environmental groups and attempt to be flexible regarding the height of emission stacks (taller is better) and the locations of emis-sions sources, such as flares, with respect to fence-line receptors (farther away is better). In addition, operators can consider conducting baseline modeling in rural areas that lack extensive monitoring data in order to build a modeling record supportive of the argument that new and modi-fied sources do not cause violations of the air quality standards.

[3] ControversiesModeling is controversial. Regulatory air dispersion models are designed

to be conservative, which raises disputes about the accuracy of the models. As technology changes or the pace of development quickens, controversy can arise about data inputs.351 Modeling is becoming increasingly impor-tant in NEPA decision making about oil and gas development.352 One of the primary causes of permitting backlogs and delay is the lack of model-ing resources at the agency level.353 Operators should address modeling well in advance of any project that may require permitting or NEPA review.

§ 6.11 Startup, Shutdown, and Malfunction Exemption[1] Elimination of the Exemption

Some equipment cannot meet emission standards during cold starts or shutdown periods.354 Regulators recognize that even the best-operated equipment can occasionally malfunction, causing excess emissions. Accordingly, EPA exempted excess emissions during startup, shutdown,

350 See Fox, supra note 346, at 8–11; Geran, supra note 349, at 4–5.351 E.g., Memorandum from Tyler Fox, Leader, Air Quality Modeling Group, EPA Office

of Air Quality Planning and Standards, to Raymond Werner, Chief, Air Programs Branch, EPA Region 2 (Feb. 29, 2012) (opining that the exemption to modeling for “intermittent” sources does not apply to air quality impacts from drilling and completions in the Marcellus Shale).

352 See EPA NEPA MOU, supra note 317, at 9–12 (specifically addressing the necessity for dispersion during NEPA evaluation of oil and gas projects).

353 See Colo. Rev. Stat. § 25-7-114.5(16) (authorizing a state environmental agency to outsource modeling due to permit backlogs).

354 See 75 Fed. Reg. 9648, 9656–57 (Mar. 3, 2010).


and malfunction (SSM) events from compliance determinations, provided that the operator met certain conditions. However, in 2008, a federal court vacated the SSM exemption for the purposes of the NESHAP program.355 As a result, EPA has eliminated the SSM exemption for both NSPS OOOO and NESHAP HH.356 Instead of providing an exemption from liability for violating the performance and emission standards during periods of SSM, EPA added an affirmative defense to civil penalties (but not injunctive relief) in the performance and emission standards for malfunction-based violations.357 EPA contends that states cannot enact blanket SSM exemp-tions in their SIPs.358 While some states have revised their implementation plans to eliminate the liability exemption,359 other states, like Utah, still have an exemption for upsets or malfunctions.360 EPA is challenging these exemptions by notifying such states that their SIPs are invalid.361

[2] SSM in PermittingIn evaluating whether oil and gas facilities have deviated from emission

limits, operators must ascertain the status of the SSM exemption in appli-cable federal and state regulations. The SSM issue is also becoming the subject of permitting disputes based on whether operators have properly calculated emissions. Environmental groups contend that operators must include SSM emissions when calculating PTE under permit programs. However, in 2011, the Wyoming Supreme Court disagreed.362 The court ruled that when calculating PTE, regulators should not include potential emissions due to cold starts and malfunctions, because those events do not represent the intended operation of the facility.363 Rather, PTE includes only emissions that occur during normal operations.364

355 Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008).356 77 Fed. Reg. 49,490, 49,508–09, 49,557–58, 49,569–70 (Aug. 16, 2012) (to be codified

at 40 C.F.R. §§ 60.5415(h), 63.762).357 Id.358 See Memorandum from John B. Rasnic, Director, Stationary Source Compliance Div.,

EPA Office of Air Quality Planning & Standards, to Linda M. Murphy, Director, Air, Pesti-cides & Toxics Mgmt. Div., EPA Region 1 (Jan. 28, 1993).

359 E.g., 5 Colo. Code Regs. §§ 1001-2:II.E, .J.360 Utah Admin. Code r. 307-107.361 E.g., 76 Fed. Reg. 21,639, 21,641 (Apr. 18, 2011).362 Sierra Club v. Wyo. Dep’t of Envtl. Quality, 251 P.3d 310, 313–14 (Wyo. 2011).363 Id. at 315.364 Id. at 314–15.


§ 6.12 EnforcementEPA and the states have escalated their enforcement efforts amid the

increased regulatory and legal activity described above. EPA has under-taken a “National Enforcement Initiative” aimed at addressing “violations from natural gas extraction and production activities causing air and water impacts that may pose a threat to human health.”365 The EPA website displays a map showing EPA inspections, evaluations, and enforcement actions in various oil and gas basins and shale plays, and has a link to a chart showing the number of EPA energy extraction inspections, evalu-ations, and enforcement actions. Moreover, a list of recent EPA consent decrees with operators in the Uintah Basin demonstrates the agency’s increased focus on enforcement:• United States v. Kerr-McGee Corp., No. 1:07-cv-01034-EWN-KMT,

2008 WL 863975 (D. Colo. Mar. 26, 2008)• United States v. Wind River Resources Corp. & Bill Barrett Corp., No.

2:09-cv-00330-TS (D. Utah Nov. 13, 2009)• United States v. Dominion Exploration & Production, Inc. & XTO

Energy, Inc., No. 2:09-cv-00331-TS (D. Utah Nov. 17, 2009)• United States v. Miller, Dyer & Co., Chicago Energy Associates & Whit-

ing Oil and Gas Corp., No. 2:09-cv-00332-DAK (D. Utah Sept. 23, 2009)

• United States v. Colorado Interstate Gas Co., No. 2:09-cv-00649-TS (D. Utah Sept. 14, 2010)

• United States v. Gasco Energy Inc. & Monarch Natural Gas LLC, No. 2:10-cv-01282-PMW (D. Utah Apr. 6, 2011)

• United States v. Questar Gas Management Co., No. 2:08-cv-00167-TS-PMW (D. Utah May 16, 2012).

As EPA and state agencies focus more and more on regulating air quality impacts from oil and gas operations, they will likely maintain or accelerate the pace of enforcement.

§ 6.13 Local Regulation[1] Shifting Focus

Although it is not specifically a regulatory development, one of the big-gest air quality challenges facing oil and gas development is opposition by groups who contend that drilling and other activities present a health risk due to excess emissions of “toxic” pollutants. For example, the media and

365 See, e.g., EPA, “National Enforcement Initiative—Assuring Energy Extraction Activi-ties Comply with Environmental Laws,” http://www.epa.gov/oecaerth/data/planning/initiatives/2011energy.html.


citizen group furor over hydraulic fracturing originally hinged on water quality concerns but has now shifted to air quality, as fracturing is blamed for excess emissions during well completions.366 As any casual consumer of the news media will attest, local governments and citizen activists are rallying to restrict or outright ban oil and gas development due to per-ceived health risks or as a means to maintain what some might consider “traditional” land uses.367 Outside organizations and universities increas-ingly conduct studies regarding whether residents face health risks from oil and gas development,368 sometimes with activist group funding.369 These studies have created headlines, even though the oil and gas industry, other organizations, and university scientists have heavily criticized them.370

[2] Scientific ControversiesIn one recent example, the National Oceanic and Atmospheric Admin-

istration (NOAA) presented data that caused the residents of the town of Erie, Colorado, to become concerned about potential public health effects from propane and benzene air emissions allegedly associated with increased oil and gas operations.371 The “report” made headline news in

366 See Harris, supra note 110.367 Jon Hamilton, Medical Records Could Yield Answers on Fracking (NPR radio broad-

cast May 16, 2012); Jon Hamilton, Town’s Effort to Link Fracking and Illness Falls Short (NPR radio broadcast May 16, 2012).

368 E.g., Stephen G. Osborn et al., “Methane Contamination of Drinking Water Accom-panying Gas-Well Drilling and Hydraulic Fracturing,” 108 Proc. Nat’l Acad. Sci. USA 8172 (May 17, 2011) (finding evidence of higher levels of dissolved methane in shallow ground-water for sites near drilling activities in the Marcellus and Utica Shales, but finding no evidence of contamination of drinking-water samples with deep saline brines or fracturing fluids).

369 E.g., Mohan Jiang et al., “Life Cycle Greenhouse Gas Emissions of Marcellus Shale Gas,” 6 Envtl. Research Letters 034014, at 8 (July–Sept. 2011) (acknowledging financial sup-port from the Sierra Club).

370 Compare Robert W. Howarth et al., “Methane and the Greenhouse-Gas Footprint of Natural Gas from Shale Formations,” 106 Climatic Change 679 (2011) (finding that the greenhouse gas “footprint” of shale gas is at least 20% greater than that of coal), with Law-rence M. Cathles III et al., “A Commentary on ‘The Greenhouse-Gas Footprint of Natural Gas in Shale Formations’ by R.W. Howarth, R. Santoro, and Anthony Ingraffea,” 113 Cli-matic Change 525 (2012) (arguing that the “Howarth” analysis is seriously flawed in that it significantly overestimates the fugitive emissions associated with unconventional gas extraction, undervalues the contribution of “green technologies” to reducing those emis-sions, and other reasons).

371 See Steven S. Brown, “Winter Air Quality Study, February-March 2011, Boulder Atmospheric Observatory, Summary of Points from 21 February 2012 Presentation to the Erie Board of Trustees” (Mar. 16, 2012); Steven S. Brown, NOAA Earth Sys. Research Lab., “2011 Air Chemistry Study at the Boulder Atmospheric Observatory,” at 9A-286, 9A290 (presented to Town of Erie, Colo. on Feb. 21, 2012) (PowerPoint presentation).


Boulder County, Colorado. Two weeks later, the Town of Erie approved a six-month moratorium on applications to conduct new oil and gas opera-tions.372 The Town requested a “second opinion” from a consulting firm, which prepared a Technical Memorandum evaluating NOAA’s data.373 The consultant reminded the Town that NOAA “does not engage in human health studies to better understand the risk of disease as a result of expo-sure to ambient air quality,” so “attempting to interpret the NOAA . . . data to understand the health risk for the citizens of Erie would not produce sci-entifically valid conclusions.”374 However, comparing the reported NOAA data to known carcinogenic lifetime risk estimates, the consultant con-cluded that, with caveats due to the limited nature of the study, Erie resi-dents faced low odds of experiencing adverse health effects.375 None of this addressed whether oil and gas operations caused some, all, or none of the detected benzene and propane. The moral of this story is that bad science makes bad policy. The initial report ignored the fundamental toxicologi-cal premise that it is the dose that makes the poison and the fundamental legal causation principle that the dose must be associated with a known cause.376 In this sort of environment, operators must prepare to work with stakeholders to present health and toxicological information in a manner that everyone will understand. Moreover, when faced with broad toxic tort suits based on alleged air impacts, operators should urge the court to issue Lone Pine-type case management orders to address concerns about the plaintiffs’ inability to establish the requisite causal connection.377

372 Town of Erie, Ordinance No. 09-2012 (Mar. 7, 2012).373 Cynthia Ellwood, “Technical Memorandum Town of Erie Air Quality Assessment,”

at 8, 10 (May 4, 2012); see also Quality Envtl. Prof ’l Assocs., “Scientific Analysis and Health Impact of Propane Levels in: Ambient Air Data of Erie Colorado,” at 6 (Apr. 2012) (noting that a prior study that the NOAA study referenced “is inherently flawed” and, thus, “these studies . . . imply (without a proper scientific assessment) that oil & gas is having a much greater impact upon air quality than was previously thought. . . .[I]t would be advisable to formally challenge certain aspects of both of these studies.”).

374 Ellwood, supra note 373, at 6.375 See, e.g., id. at 8–9.376 See King, supra note 111, at 345, 353–58.377 See Strudley v. Antero Res. Corp., No. 2011-CV-2218 (Colo. Dist. Ct. May 9, 2012).

In Lore v. Lone Pine Corp., No. L-33606-85, 1986 WL 637507 (N.J. Super. Ct. Nov. 18, 1986) (unpublished), plaintiffs sued a landfill for loss of property value and pollution from the site. The court issued case management orders requiring the plaintiffs to submit proof of exposure to the alleged toxic substances as well as medical and real estate reports showing harm before engaging in discovery. Id. at *1–2. The court found plaintiffs’ evidence insuf-ficient to support a prima facie cause of action based upon property diminution or personal injuries, and dismissed the case with prejudice. Id. at *3–4.


[3] Local ControlLocal governments often enact regulations that address perceived envi-

ronmental or health risks associated with oil and gas development. In response to increased oil and gas activity, local governments are moving rapidly to regulate many phases of upstream and midstream operations, resulting in controversies and threatened litigation.378 Some jurisdictions have enacted setback and environmental requirements, whereas others have imposed temporary moratoria.379 Significant disputes arise over these regulations, raising important legal and practical issues concerning the nature, location, and pace of development.380 In many states, like Colo-rado, the courts have ruled that oil and gas conservation commission regu-lations do not entirely preempt local regulation of oil and gas, although state laws may preempt local rules imposing technical or operational requirements.381

[4] Preemption LitigationTwo recent cases involving development in shale plays in the eastern

United States indicate that local governments may retain considerable power to regulate, and may use environmental issues as a justification for significant restrictions in development plans, including fundamental choices over where to drill. In 2011, the towns of Dryden and Middle-field in New York each amended their zoning laws to prohibit “land uses” related to upstream and midstream operations.382 A landowner challenged

378 See, e.g., Will Shoemaker, “Gas producer sues county,” Gunnison Country Times, June 9, 2011.

379 E.g., 2 Colo. Code Regs. § 404-1:603 (statewide setbacks for drilling and well servic-ing operations and high density areas); Boulder Cnty., Colo., Res. 2012-46 (Apr. 16, 2012) (extension of moratorium on processing oil and gas development applications through February 4, 2013).

380 See, e.g., Letter from John E. Matter, Jr., Colo. Asst. Attorney General, to Ron Carl, Arapahoe Cnty. Attorney’s Office (Dec. 28, 2011) (opining that Colorado law preempts Arapahoe County’s proposed oil and gas regulations). In Longmont, Colorado, opponents of fracking put Question 300 on the ballot for the November 6, 2012, election. If Question 300 passes, the result would be a ban on fracking within the city limits. See Scott Rochat, “Ballot Question 300 would ban fracking in Longmont,” Longmont Times-Call, Oct. 6, 2012. In a related matter, the Colorado Oil and Gas Conservation Commission sued the city of Longmont over a new Longmont ordinance meant to keep drilling out of residential areas, asserting that the ordinance is preempted by the Colorado Oil and Gas Conservation Act and its implementing regulations. Colo. Oil and Gas Conservation Comm’n v. Longmont (Colo. Dist. Ct., Boulder Cnty., filed July 30, 2012); see Colo. Rev. Stat. §§ 34-60-101 to -128.

381 Town of Frederick v. N. Am. Res. Co., 60 P.3d 758, 765 (Colo. Ct. App. 2002) (holding that local setback, noise abatement, and visual impact regulations were preempted).

382 E.g., Town of Dryden, N.Y., Res. 126 (effective Aug. 19, 2011), http://dryden.ny.us (search “resolution 126”); Town of Middlefield Zoning Law, N.Y., Local Law No. 1 (adopted


the Middlefield law, and a gas exploration company that owned gas leases challenged the Dryden ordinance.383 Both plaintiffs argued that New York law preempted the local laws.384 The courts disagreed, holding that the rel-evant state law did not preempt the local prohibitions because it extended to local regulation of oil and gas industry “operations,” not local regulation of “land uses.”385 In other words, “[t]he state maintains control over the ‘how’ of [oil and gas drilling] procedures while the municipalities maintain control over the ‘where’ of such exploration.”386

§ 6.14 Conclusion: Overcoming Regulatory Strategies That Threaten Development

The clear trend in air quality regulation for the oil and gas industry is that the federal, state, and local stakeholders will place more restrictions and limitations on activities that may affect the environment. These changes in environmental law and regulations and reinterpretations of permitting, compliance, and enforcement policies may result in more stringent and costly construction, drilling, completion, storage, processing, and com-pression compliance requirements. The Clean Air Act and comparable state laws and regulations already restrict the emission of air pollutants from many sources and impose various complex permitting, monitor-ing, and reporting requirements. These laws and regulations can require preapproval for the construction or modification of projects or facilities expected to produce or significantly increase air emissions, strict compli-ance with air permit requirements, and utilization of specific equipment or technologies to control emissions. The permitting process can delay the development of oil and gas projects. For all of these reasons, operators must understand the new and evolving air quality regulations impacting oil and gas development in the West.

June 14, 2011), http://www.middlefieldny.com/documents--forms.html (select link titled “Zoning Law 2011”).

383 “Second Judge in State Backs Local Ban on Gas Drilling,” N.Y. Times, Feb. 24, 2012; Verified Petition and Complaint at 1, 6, Anschutz Exploration Corp. v. Town of Dryden, 940 N.Y.S.2d 458 (App. Div. 2012).

384 Petitioner-Plaintiff ’s Memorandum of Law in Support of Verified Petition and Com-plaint, Affidavit of Gregory H. Sovas at 7, Anschutz Exploration Corp., 940 N.Y.S.2d 458; Cooperstown Holstein Corp. v. Town of Middlefield, 943 N.Y.S.2d 722 (App. Div. 2012); Petitioner-Plaintiff ’s Memorandum of Law in Support of Verified Petition and Complaint at 11, Affidavit of Sovas at 3, Anschutz Exploration Corp., 940 N.Y.S.2d 458.

385 Cooperstown Holstein Corp., 943 N.Y.S.2d 722; Anschutz Exploration Corp., 940 N.Y.S.2d 458.

386 Cooperstown Holstein Corp., 943 N.Y.S.2d at 729.