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CHAPTER 21

Where Do We Go From Here – Environmental Trends from the Trenches

James Martin

Beatty & Wozniak, P.C.

Denver, Colorado

Jennifer Keane

Baker Botts L.L.P.

Austin, Texas

§21.01 INTRODUCTION

There is a lot to talk about when it comes to citizen and agency enforcement of federal

environmental statutes. Environmental nongovernmental organizations (eNGOs) continue their

efforts to enforce mandatory duties under statutes such as the Clean Air Act. They also continue

to probe for legal strategies to force action on discretionary provisions of federal statutes. Title

V of the Clean Air Act continues to be a source of conflict. And litigants and courts continue to

grapple with the concept of continuing violation and statutes of limitation.

eNGOs are escalating their efforts to use the National Environmental Policy Act

(NEPA) to slow or stop projects related to fossil fuel production, transportation, and use. There

is a parallel and increasingly energetic effort by the Environmental Protection Agency (EPA) to

leverage its own NEPA authorities to “encourage” action agencies to modify or even reject

proposed projects or to force the proponent to accept mitigation measures that the action agency

may lack the statutory authority to require and which affect a project’s economics. The threat of

climate change appears to be a principal motivator and the Council on Environmental Quality’s

(CEQ) recent guidance on consideration by federal agencies of greenhouse gas emissions and

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climate change figures prominently in these debates. Regardless of the fate of that guidance,

anyone contemplating a project that has a federal nexus should be prepared for a NEPA battle.

At the same time, in at least parts of the country – especially EPA Regions 3, 6, and 8,

see the map below – the agency has pursued an aggressive enforcement agenda. In many cases

they have relied upon the results of extensive and demanding section 114 letters to elicit the very

information that leads to enforcement actions. In a number of cases, those enforcement actions

lead to consent decrees in which the targeted company agrees to implement extra-regulatory

measures that go well beyond what EPA has been able to implement by rulemaking.

Equally problematic is that in at least some cases, EPA (and sometimes states) rely upon

imprecise and broad “general duty” provisions in regulations, state implementation plans (SIPs),

or in the federal Clean Air Act as the hook in these enforcement efforts. That problem is likely

to expand with the advent of EPA’s methane regulations for the oil and gas industry, as those

provisions contain a “general duty to safely maximize resource recovery and minimize releases

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to the atmosphere.”1 Just as one example, there almost certainly will be conflict over the

definition of “component,” whether a component is “leaking” or “venting,” and whether either is

unlawful in any particular circumstance. Regardless of the definitional meanings, a “general

duty” violation might be cited as the basis for enforcement.

In Part 1 of this paper, we survey recent federal court decisions that provide insight into a

number of the facets that surround enforcement of federal environmental statutes in the oil and

gas arena, with an emphasis on the Clean Air Act (CAA). In Part 2, we focus on recent

enforcement settlements that include the use of CAA section 114 letters to aid enforcement, the

entry of broad consent decrees, and the demand for extra-regulatory measures in those consent

decrees.2

§21.02 PART 1. RECENT DEVELOPMENTS IN THE LAW

[1] Standing.

In April 2016, a United States Magistrate Judge in the District Court of the District of

Oregon took standing doctrine to, and almost certainly beyond, its generally accepted scope. In

Juliana v. United States3, several minors (represented by eNGOs) sued the President and his

cabinet asserting that they knew of the threat climate change posed to the nation and world but

have failed to take adequate steps to avert catastrophe. Among other things the plaintiffs asked

the court to find that the defendants had violated the plaintiffs’ constitutional rights to life, liberty

and property. The plaintiffs also sought a declaration that section 201 of the Energy Policy Act

is facially unconstitutional. In addition, they asserted a public trust claim. In all, they are

seeking a court order requiring the United States government to phase out the use of fossil fuels.

1 40 C.F.R Part 60.5375(a)(4). 2 The authors would like to thank Patrick Leahy of Baker Botts LLP for all of his contributions to this paper. 3 Juliana v. United States, 2016 U.S. Dist. LEXIS 52490, 46 E.L.R. 20072 (6-15-cv-1517-TC) (D. Or. 2016)

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The court acknowledged that the plaintiffs were asserting a novel theory of law, and for

the most part do not challenge a specific federal action. Nevertheless, the court denied motions

to dismiss claiming the plaintiffs lacked standing.

The court first pointed out that climate change could affect not only virtually every living

human, but humans not yet born.4 Yet the court elided the requirement that a plaintiff

demonstrate something more than a generalized grievance about the conduct of government,

Flast v. Cohen,5 and concluded that the plaintiffs had shown sufficient evidence of concrete

particularized harm.6 Working from there, the court encountered no difficulty in finding that the

plaintiffs’ injuries could fairly be traceable to the unspecified actions of third parties. Neither did

the court tarry long in finding that a theoretical order from EPA could redress the claimed

injuries (and assumed the agency had sufficient delegated authority to do just that).

Somewhat surprisingly, Judge Aiken adopted the magistrate judge’s findings and

recommendations.7 The court affirmed the magistrate’s findings on standing. The court also

discussed at some length the political question doctrine, but also rejected that as a basis for

dismissing the lawsuit. More spectacularly, the court decided that in its reasoned judgment, “ I

have no doubt that the right to a climate system capable of sustaining human life is fundamental

to a free and ordered society.”8 Beyond announcing that it had found a new fundamental right,

the court went even further to state that at least some acts constitute a due process violation:

In framing the fundamental right at issue as the right to a climate system capable of

sustaining human life, I intend to strike a balance and to provide some protection against

the constitutionalization of all environmental claims. On the one hand, the phrase

4 Id. 5 Flast v. Cohen, 392 U.S. 83, 106 (1968). 6 Juliana, supra. 7 Juliana v. United States, 2016 U.S. Dist. LEXIS 156014, 46 ELR 20175, 83 ERC (BNA) 1598 (D. Or. 2016). 8 Id. at 49.

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"capable of sustaining human life" should not be read to require a plaintiff to allege that

governmental action will result in the extinction of humans as a species. On the other

hand, acknowledgment of this fundamental right does not transform any minor or even

moderate act that contributes to the warming of the planet into a constitutional violation.

In this opinion, this Court simply holds that where a complaint alleges governmental

action is affirmatively and substantially damaging the climate system in a way that will

cause human deaths, shorten human lifespans, result in widespread damage to property,

threaten human food sources, and dramatically alter the planet's ecosystem, it states a

claim for a due process violation. To hold otherwise would be to say that the Constitution

affords no protection against a government's knowing decision to poison the air its

citizens breathe or the water its citizens drink. Plaintiffs have adequately alleged

infringement of a fundamental right.9

This standing decision may not survive long. Nevertheless, it illustrates the perseverance

of eNGOs in their search for friendly fora as those eNGOs look for new and different ways to

force action on climate change. It also suggests a willingness on the part of at least some

members of the judiciary to find new rights and to assume responsibility for managing the

federal government’s response to climate change. With the advent of a new administration in

Washington, D.C., one should expect more creative efforts at enlisting the federal courts in the

battle.

[2] When Does a Cause Accrue.

Two cases decided in 2016 provide interesting, and perhaps inconsistent answers to the

question of when a claim accrues. In Sierra Club v. Oklahoma Gas & Elec. Co,10 the panel was

9 Id. at 51-52. 10 Sierra Club v. Oklahoma Gas & Elec. Co, 816 F.3d 666 (10th Cir. 2016).

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faced with the question of when a claim accrued to the plaintiff, which complained that the

defendant had initiated a major modification of a coal-fired electric generating unit without first

having secured a Prevention of Significant Deterioration (PSD) permit.11

The district court had dismissed the Sierra Club’s claim, finding that the claim had

“accrued” at the commencement of modification of the boiler, and that date was more than five

years from the date the Sierra Club initiated its claim. On appeal, the plaintiff argued in the

alternative that the defendant committed a new, discrete violation on each day the modification

continued (repeated violations), or that the violation continued until the modification was

completed (continuing violation).

The Tenth Circuit majority rejected each theory. The majority described the violation as

a single, discrete act which accrued into a claim on the day that construction was initiated. Thus,

the majority found the statute of limitations had run and the claim was time barred. The

dissenting judge, on the other hand, would have found that the violation continued throughout

the construction period.

It may be useful to note that there are several circuit court decisions in agreement that a

PSD claim is barred if brought more than five years after construction has been completed.12 But

those fact situations were different from the facts in Sierra Club.

A very recent cased from the Sixth Circuit stands somewhat in contrast with these

decisions. The defendant in United States v. DTE Energy Company,13 decided to overhaul one of

its units at the largest coal-fired electric generating units in Michigan. It apparently notified the

Michigan Department of Environmental Quality that while emissions would significantly

11 40 U.S.C. §§770-7492. 12 United States v. Midwest Generation, LLC., 720 F.3d 644, 646-647 (7th Cir. 2013); United States v. EME Homer

City Generation, L.P., 727 F.3d 274, 283-288 (3rd Cir. 2013). 13 United States v. DTE Energy Company, ____F.3 ___, 2017 U.S. App. LEXIS 416, 2017 FED App. 0006P (6th

Cir. 2017).

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increase and would otherwise constitute a major modification requiring a New Source Review,

the utility planned to take advantage of an NSR exception for emissions attributable to demand

growth. EPA disagreed and filed an enforcement action. On the first go-round, the district court

decided that EPA could not pursue such an action unless it first demonstrated that emissions

actually had increased. The Sixth Circuit reversed and remanded.14

On remand, the district court again held for the utility, though on different grounds.

Basically, the district court found that the agency had to take the utility’s emissions projections at

face value. On appeal the second time, the Sixth Circuit reversed again. The Sixth Circuit

decided that EPA is entitled to make an in-depth assessment of the utility’s calculations, and the

utility had fallen short. The court acknowledged that the utility was not required to get EPA’s

approval before proceeding, but the utility did so at its own risk: the applicability of NSR must

be determined before construction. The court’s decision approved of an EPA enforcement action

seeking to force the utility to get an NSR permit even though the agency’s calculations differed

from the utility’s and were suspect in the view of at least one member of the panel. That

apparently is so in the Sixth Circuit even if actual emissions decrease post-modification.

[3] Agency Action Withheld.

No year passes without its share of mandatory duty litigation, and 2016 was no exception.

One important development centers on the question of whether exploration and

production (E&P) waste is adequately regulated under the Resource Conservation and Recovery

Act (RCRA), codified at various sections of 42 U.S.C. § 6901, et. seq. In Environmental

Integrity Project v. McCarthy,15 a group of eNGOs claimed that EPA had a nondiscretionary

duty under Subtitle D of RCRA to review and if necessary revise the agency’s E&P regulations,

14 United States v. DTE Energy Co., 711 F.3d 643 (6th Cir. 2013). 15 Environmental Integrity Project v. McCarthy, No. 1:16-CV-00842-JDB (D.D.C.).

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which can be found at 40 C.F.R. Part 257. The plaintiffs alleged that the agency had a duty to

conduct such a review every three years, but had not done so since 1988.

On December 28, 2016, the court granted a motion of the plaintiff and defendant (but

over the objection of intervenors) for entry of a consent decree to resolve the case over the

agency’s ostensible duty to conduct its review of its regulations for management of E&P wastes.

By March 15, 2019, the agency must either formally determine that any revision is unnecessary

or propose a rulemaking for revision of the Subpart D requirements. If the agency does decide to

undertake rulemaking, the consent decree requires the agency to take final action no later than

July 15, 2021.16

The eNGOs no doubt would like to see the agency conclude that E&P wastes should be

regulated under Subpart C, which controls management and disposal of hazardous wastes.

However, a 1980 amendment effectively exempted E&P wastes from regulation under Subtitle C

of RCRA.17 It required EPA to study the chemical and physical qualities of E&P waste and to

then determine either to promulgate regulations under Subtitle C or decide that regulation is

unwarranted. Were the agency to opt for regulation, any such regulations could take effect only

if authorized by Congress. (In 1988, EPA decided that E&P wastes should not be regulated

under Subtitle C.18)

Another case, Sierra Club v. McCarthy,19 perfectly illustrates the dilemma in which

federal agencies find themselves when faced with mandatory duty lawsuits: settle in hopes of

reaching an agreed-upon schedule that might be achievable, or fight it out and end up with a

16 INSIDE EPA reports that the State of North Dakota is challenging that consent decree, but no further information

was available at the time this article was being written. 17 42 U.S.C. § 6921(b)(2)(A)-(C). 18 Regulatory Determination for Oil and Gas and Geothermal Exploration, Development, and Production Wastes,

53 Fed. Reg. 25446 (July 8, 1988) 19 Sierra Club v. McCarthy, 2016 U.S. Dist. LEXIS 33435 (D.N.CA. 2016).

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deadline that will, at very best, strain agency resources on an issue that was not an agency

priority in the first place.

In this case, the plaintiffs filed suit pursuant to 42 U.S.C. § 7604(a). They alleged that

while the agency had issued maximum achievable control technology (MACT) standards for

paper mills and nutritional yeast manufacturers pursuant to 42 U.S.C. § 7412(d)(1)-(2), the

agency had been dilatory in reviewing those emission standards “in light of developments in

practices, processes, and control technologies” as well as in investigating any residual health risk

remaining after implementation of the MACT standards.

EPA admitted it had missed its statutory deadline and offered up an affidavit from the

Acting Assistant Administrator for Air and Radiation proposing a timetable for fulfilling its

obligations. She averred that “anything less ‘could jeopardize both the soundness of the

regulatory actions and their legal defensibility.’” The plaintiffs, though, complained that the

EPA proposal was merely “reasonable” whereas they believed the court should order a schedule

that is “feasible.” The court ultimately agreed in substantial part and ordered an abbreviated

timetable to bring the agency into compliance.

Environmental Integrity Project v. U.S. EPA,20 did not involve a claim that EPA had

failed to perform a nondiscretionary duty. Instead, the plaintiffs complained that EPA had failed

to respond within a reasonable time to a petition for rulemaking concerning ammonia emissions

into the atmosphere from concentrated animal feed lots (CAFO). The plaintiffs styled the claim

as an action under the Administrative Procedure Act, 5 U.S.C. § 551 et seq. asserting that a

response to the petition had been unreasonably withheld. In this case, the United States agreed

the APA gave rise to EPA’s duty to respond to the petition for rulemaking.21 However, the

20 Environmental Integrity Project v. U.S. EPA, 160 F.Supp.3d 50 (D.D.C. 2015). 21 5 U.S.C. § 555(b), (e).

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United States argued that waiver of sovereign immunity came courtesy of the citizen suit

provision of the Clean Air Act, 42 U.S.C. § 7604(a). That allowed the United States to argue

that the plaintiffs had failed to satisfy a statutory condition precedent for pursuing such a claim –

the statutory 180-day notice requirement.

All that turned, of course, on whether the citizen suit provisions contemplated suits that

effectively were seeking to force a discretionary act. Ultimately, the court agreed that the Clean

Air Act’s citizen suit provisions “provide the cause of action for plaintiff’s claim that EPA

unreasonably delayed in responding to the 2011 petition for rulemaking….” There followed the

inescapable conclusion that section 7604(a) requires notice to the administrator, and that such

notice is jurisdictional. Accordingly, the plaintiffs’ claims were dismissed.22

[4] Diligent Prosecution.

Group Against Smog and Pollution v. Shenango, Inc.,23 was hardly earth-shattering, but it

is worthy of mention. Here, plaintiffs had filed a citizen suit provision pursuant to 42 U.S.C.

§ 7604(a)(1), claiming violations of emission standards at a nearby coke manufacturing and by-

products recovery facility with a history of air pollution issues. However, the state previously

had initiated an action raising the same issues as were raised in the citizen suit. That case was

resolved by entry of a consent decree. Consequently, at the district court the defendant filed a

Rule 12(b)(1) and 12(b)(6) motion to dismiss the claim for lack of subject matter jurisdiction,

arguing that the state already was “diligently prosecuting” an action in court to require

compliance with emission limits. The district court granted that motion.

On appeal, the court first addressed the question of whether the diligent prosecution bar

was jurisdictional and amenable to a motion to dismiss for lack of subject matter jurisdiction, or

22 (For a similar case, see Humane Society of the United States v. McCarthy, 2016 U.S. Dist. LEXIS 126987 46,

E.L.R. 20154, 83 E.R.C. (BNA) 1361 (D.D.C. 2016). 23 Group Against Smog and Pollution v. Shenango, Inc., 810 F.3d 116 (3d Cir. 2016).

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whether it is non-jurisdictional and should be decided through a 12(b)(6) motion to dismiss for

failure to state a claim. The answer – it is non-jurisdictional.

On the merits, the court grappled with the issue of whether a citizen suit could be

maintained under section 7604(a)(1) when a consent decree had previously been entered. The

court adverted favorably to decisions in other circuits holding that an underlying case was

diligently pursued if it resulted in a consent decree. The court ultimately adopted the same line

of reasoning and affirmed the district court’s decision.

While Askins v. Ohio Dept. of Agriculture,24 was not a diligent prosecution case, it does

reinforce the principle that citizen suit provisions are not all-encompassing. In Askins, the

plaintiff argued, among other things, that a discharge permit was invalid because the state had

failed to notify EPA that the state had transferred water quality regulation from one agency to

another. The court quickly disposed of that argument by pointing to the Clean Water Act itself:

compliance with a permit shall be deemed compliance for purposes of the Act’s citizen suit

provisions, with sections 1311, 1312, 1316, 1317, and 1343 of the Act.25

The plaintiffs also tried to assert a private cause of action against the regulators (who

were not the dischargers), and the court easily rejected that argument, as well. The court went on

to emphasize the limited nature of citizen suits under the Act: “[t]he citizen suit serves only as a

backup, ‘permitting citizens to abate pollution when the government cannot or will not command

compliance.’”26

24 Askins v. Ohio Dept. of Agriculture, 809 F.3d 868 (6th Cir. 2016). 25 See 33 U.S.C. § 1342(k). 26 Id. at 875, citing Gwaltney of Smithfield v. Chesapeake Bay Found., 484 U.S. 49, 62 (1987) (emphasis in

original).

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[5] Blockbuster Cases.

There was at least one blockbuster case in 2016: Mingo Logan Coal Co. v.

Environmental Protection Agency, 829 F.3d 710 (D.C. Cir. 2016). The plaintiff-appellant had

planned to construct a surface coal mine using the technique known as mountaintop mining.

The proposal would have resulted in burial of almost eight miles of three streams with mine

spoils. In 2007, the Corps of Engineers had granted the mining company a section 404 permit

over objections from EPA. Four years later, EPA completed a study that found the project would

result in unacceptable adverse impacts to the environment and withdrew approval from two of

the disposal sites. (In common parlance, EPA “vetoed” the 404 permit.)

In an earlier case, the D.C. Circuit rejected a challenge to EPA’s authority to withdraw

the permits after they had been issued.27 The instant case revolved around the question of

whether EPA’s veto was arbitrary, capricious, an abuse of discretion, or otherwise not in

accordance with law.28 The court ultimately rejected the APA claims.

However, the case is more interesting – and perhaps of significant interest to the new

Presidential administration – in its discussion of how this very important court will review

changes in agency policy. It averred that “[w]hen an agency changes policy, however, it must in

some cases ‘provide a more detailed justification than what would suffice for a new policy

created on a blank slate,’”29 The agency would not have to convince the reviewing court that the

reasons for the new policy are “better” than those that supported the old policy. But “if a ‘new

policy rests upon factual findings that contradict those which underlay [an agency’s] prior

27 Mingo Logan Coal Co. v. EPA, 714 F.3d 608 (D.C. Cir. 2013). 28 5 U.S.C. § 706(2)(A). 29 Id. at 718-719, citing FCC v. Fox Television Stations, Inc., 556 U.S., 502, 515 (2009).

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policy,’ the agency ‘must’ provide ‘a more detailed justification’ for its action.30 We may well

see this dictum repeated over and over in the next few years.

[6] Weaponizing NEPA.

eNGOs broadly opposed to the production and use of fossil fuels increasingly are using

NEPA as a weapon to delay and even halt projects. Much of the litigation has focused on the

Federal Energy Regulatory Commission (FERC), which so far has pushed back successfully.

Even more recently, EPA staff have taken up the cudgel against FERC (and other agencies),

urging upon other agencies the argument that NEPA requires a far-ranging analysis of the

impacts of the entire value chain of oil and gas.

In Sierra Club v. FERC,31 the plaintiffs challenged a FERC decision to authorize

conversion of a natural gas terminal in Texas to enable gas exports. The plaintiffs asserted that

FERC’s NEPA review should have evaluated:

(a) how the project might induce greater domestic production of natural gas;

(b) the cumulative effects of this project when combined with other projects;

(c) whether, in evaluating emissions in pounds per megawatt-hour rather than tons per

year, FERC understated the project’s emissions.

It appears the plaintiffs sought to significantly expand the scope of analysis required by

NEPA. They first argued that the analysis of direct and indirect effects should have been broader

to include everything for which the export facility could be a “but-for” cause. The court

responded by limiting the scope of the agency’s NEPA obligations by stating that an indirect

effect must be “’sufficiently likely to occur that a person of ordinary prudence would take it into

30 Id., citing to Ark Initiative v. Tidwell, 816 F.3d 119, 127 (D.C. Cir. 2016). 31 Sierra Club v. FERC, 827 F.3d 36 (D.C. Cir. 2016).

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account in reaching a decision.’”32 The court then dismissed the argument that a NEPA review

of an export facility ought to have examined the potential increase in domestic natural gas

development. The plaintiffs’ claim that the NEPA review also should have examined the

cumulative impacts of all existing and proposed export facilities met with a similar fate. In

language sure to be repeated by litigants in the future, the court held that a “NEPA cumulative-

impact analysis need only consider the ‘effect of the current project along with any past, present

or likely future actions in the same geographic area’ as the project under review.”33

That same day, the D.C. Circuit also rejected a Sierra Club challenge to an export

terminal planned for Louisiana.34 In this case, the project proponent wanted to increase

production capacity at its existing facility. Much as in the case described above, the Sierra Club

argued that increased exports would induce greater domestic production of natural gas with

attendant air quality impacts, would cause domestic natural gas prices to increase, and this in

turn would prompt electric utilities to use more coal to generate electricity.

For this project FERC had prepared an environmental assessment. The court declined to

find the FERC action arbitrary and capricious. The panel noted that while FERC could authorize

the increase in capacity, only the Secretary of Energy could authorize increased exports. Thus,

in the court’s view the Commission’s order was not the proximate cause of the indirect effects

the plaintiff complained of. (That same legal dichotomy was a factor in both decisions.)

[7] EPA’s Reactions.

EPA’s NEPA review teams have taken a decidedly aggressive stance in response to the

way in which FERC is evaluating indirect and cumulative impacts. As an example, on October

32 Id. at 46-47, citing City of Shoreacres v. Waterworth, 420 F.3d 440, 453 (5th Cir. 2005). 33 Id. at 50, citing TOMAC, Taxpayers of Michigan Against Casinos v. Norton, 433 F.3d 852, 864 (D.C.Cir.

2006)(emphasis added). 34 Sierra Club v. FERC, 827 F.3d 59 (D.C. Cir. 2016.

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11, 2016, the chief of the NEPA Implementation Section for Region 5 (on behalf of Regions 3, 4,

and 5) wrote to the Secretary of FERC about the Leach Xpress Project and the Rayne Xpress

Expansion Project (interstate pipeline projects). EPA’s letter and attachment raised a range of

issues with FERC’s FEIS for these projects.

In particular, the letter stressed that the FEIS’s analysis of climate change was

inadequate, and insisted that the agency assess the impacts of end use product combustion “as an

example of an indirect emission that should be calculated for each alternative considered.”

EPA’s letter described the FERC analysis as “very concerning” and requested a headquarters-

level meeting to “seek a definitive resolution to this matter before you [FERC] publish a record

of Decision (ROD) and so you do not continue to take this approach in additional NEPA

documents.35

[8] CEQ Guidance.

In its comments on other agencies’ NEPA documents, EPA has relied heavily upon Final

Guidance issued by the Council on Environmental Quality (CEQ). CEQ’s Guidance also often

makes an appearance in litigation brought by eNGOs that oppose proposed federal actions

ranging from resource management plans prepared by federal land managers to leasing

decisions, applications for permits to drill, rights-of-way for pipeline and gathering systems, and

so on.

The guidance has a long history. In response to a petition filed with CEQ by several

eNGOs, CEQ issued an initial draft of the greenhouse guidance in 2010.36 This draft endured

35 Available at http://www.eenews.net/assets/2016/10/13/document_gw_08.pdf (last visited Jan. 16, 2017)

(emphasis added). For additional flavor, visit http://www.eenews.net/stories/1060044234 (last visited Jan. 16,

2017); http://www.eenews.net/stories/1060044726 (last visited Jan. 16, 2017);

https://electricitypolicy.com/News/epa-criticizes-ferc-eis-gas-pipeline-project (last visited Jan. 16, 2017) 36 https://www.whitehouse.gov/sites/default/files/microsites/ceq/20100218-nepa-consideration-effects-ghg-draft-

guidance.pdf.

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criticism from many quarters, and was followed by a new draft in 2014.37 That draft was more

comprehensive (for good or ill). It retained a quantitative threshold of greenhouse gas emissions,

above which a project would be required to quantify emissions of greenhouse gases. The second

draft also included language intended to clarify the extent of analysis needed of upstream and

downstream emissions. It also directed agencies to conduct a “life cycle” analysis of fossil fuel

projects.

The Final Guidance, issued August 1, 2016, can be found at

https://www.whitehouse.gov/sites/whitehouse.gov/files/documents/nepa_final_ghg_guidance.pdf

(last visited Jan. 16, 2016); 81 Fed. Reg. 51866 (Aug. 5, 2016). It closely resembles the second

draft of the guidance, though it removed the references to a threshold quantity of greenhouse gas

emissions and to “life cycle” analyses while more explicitly stating that the Final Guidance

would apply to NEPA analyses of land and resource management decisions. The Final Guidance

replaced the requirement that agencies conduct a life cycle analysis with the admonition that

“NEPA reviews for proposed resource extraction and development projects typically include the

reasonably foreseeable effects of various phases in the process, such as clearing land for the

project, building access roads, extraction, transport, refining, processing, using the resource,

disassembly, disposal, and reclamation.”38

The Final Guidance has been stoutly defended by eNGOs and criticized by industry and

others. Among the most common critiques, some have argued that the Final Guidance expands

the scope of NEPA analysis required for proposed federal actions beyond the confines of the

NEPA statute, particularly for resource management planning and resource development

activities. They also argue that the Final Guidance requires that, in most cases, federal agencies

37 https://www.gpo.gov/fdsys/pkg/FR-2014-12-24/pdf/2014-30035.pdf. 38 Id. at 14.

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quantify the direct, indirect, and cumulative emissions of greenhouse gases, even though such

estimates necessarily will be speculative. That would entail of the emissions not only of a

proposed oil and gas upstream development project but also of transporting the product, refining

and processing it, using it, disassembly of the project and disposal. Similarly, pipelines and

refineries would be required to quantify the emissions of upstream development. The FERC

cases cited above raise the question of whether this falls within the scope of the NEPA statute.

The CEQ Guidance also seems to require the action agency to assess potential impacts of

climate change. That could be a daunting task in many cases. As an alternative, the Guidance

suggests the use of the Social Cost of Carbon (SCC) in calculating the long-term effects of

greenhouse gas emissions but the SCC tool poses its own legal and economic issues. Finally, the

Final Guidance seems to reinforce an emerging theme that CEQ is trying to transform NEPA

from a procedural statute to a substantive one.

[9] eNGO NEPA/GHG Litigation.

Even before the 2016 presidential election, environmental NGOs were energetically

using litigation as part of their larger strategy to slow and even stop development of fossil fuels.

That is particularly true of proposals to develop oil and gas on federal lands. In the wake of the

election, there is every reason to believe that activity will accelerate. To date, they have

exhibited both persistence and creativity in these efforts. We have two recent examples to share

with you.

First, in late 2016 Wild Earth Guardians filed suit against the Secretary of the Interior

challenging BLM oil and gas lease sales that occurred over the course of several years in

Colorado, Utah, and Wyoming.39 The plaintiffs allege that BLM failed adequately to assess and

39 Wild Earth Guardians v. Sally Jewell, Case No. 1:16-cv-10724-RC (Supplemented Complaint for Declaratory and

Injunctive Relief filed Nov. 11, 2016) (D.D.C. 2016).

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disclose emissions of greenhouse gases and impacts to climate. As presaged by the preceding

discussion, they assert that BLM failed to quantify the likely greenhouse gas emissions account

for consequent impacts to the climate. They also assert that BLM was required to, but failed to

analyze the downstream emissions and associated climate risks, and suggest that BLM could

have used the Social Cost of Carbon to do so.

For those manifold sins, the plaintiffs have asked the court to not just remand the matters

to BLM, but instead to (a) declare that the leasing authorizations violate NEPA and (b) vacate

the leasing authorizations and void the underlying leases. Moreover, the plaintiffs appear to seek

from the court an order requiring BLM to complete a programmatic EIS on the entirety of its oil

and gas program. Though the complaint is unclear on this point, it also appears the plaintiffs

want the court to impose a moratorium on leasing pending the completion of that EIS.40

The same plaintiff, in a matter stylized as a petition for review,41 is challenging another

lease sale conducted by the Colorado BLM office of lands located within the Denver

Metropolitan Area/North Front Range ozone nonattainment area. Here, the plaintiffs assert that

the BLM should have completed a “conformity” analysis before conducting the lease sale.

EPA’s general conformity rules, 40 C.F.R. Parts 51 and 93, are hardly clear and understandable,

but to the authors’ knowledge this is a case of first impression; it is not at all clear that an action

(e.g., a lease sale) that does not authorize any ground disturbance actually triggers the general

conformity requirements. It is equally unclear what would be served by conducting a conformity

40 On January 20, 2016, WildEarth Guardians and the Environmental Law Clinic at UC Irvine School of Law filed a

petition with the Secretary of the Interior seeking a programmatic environmental impact statement that evaluates the

direct, indirect, and cumulative impacts of BLM’s oil and gas leasing program on climate change.

http://www.wildearthguardians.org/site/DocServer/APA_Petition_BLM_WildEarth_Guardians_1_18__Final_.pdf. 41 While stylized as a petition for review, the plaintiffs claim the action arises under both the APA and the Clean Air

Act, 42 U.S.C. § 7506(c).

19

analysis when the state has adopted a State Implementation Plan designed to bring the

nonattainment area into attainment. Nevertheless, this is a case to watch.

§21.03 PART 2: EPA ENFORCEMENT

On October 1, 2016, EPA’s national enforcement initiatives (NEIs) for fiscal years 2017

to 2019 took effect.42 Unless changed by the new Administration, this next three year cycle will

see EPA adding two new enforcement initiatives, and renewing and enlarging several current

initiatives. Notably, EPA has elected to continue its initiative focused on energy extraction

activities, first introduced in 2011 to respond to the increased frequency of hydraulic fracturing.

While a new Administration may have different enforcement priorities, the cases

discussed in this section—EPA settlements from 2014 to 2016 addressing air emissions, oil

spills, wetlands damages, and violations of the general duty clause in EPA’s Risk Management

Program—continue to be important to the energy sector several reasons. First, these cases

demonstrate the changing level of expectations for the upstream and midstream industries, in

terms of incident prevention measures and mitigation after an incident occurs. Second,

regardless of which administration is in office, large events will have large consequences. Some

of the cases discussed here, notably spill cases, have had large costs and large operating

consequences for the affected companies. Information about what went wrong—and how the

companies have voluntarily addressed those events—may provide useful insights for companies

seeking to avoid similar incidents.

They also provide notice of the types of sweeping concessions EPA (and states) can

obtain as injunctive relief when environmental violations occur. Many of the requirements

companies agree to as injunctive relief in these settlements go far beyond any applicable rule or

42 Press Release, U.S. Environmental Protection Agency, EPA Announces National Enforcement Initiatives for

Coming Years (Feb. 2, 2016) (available online at https://www.epa.gov/newsreleases/epa-announces-national-

enforcement-initiatives-coming-years)

20

regulation--making increased enforcement an attractive mechanism for EPA to drive internal

agency policies in ways it could not achieve through regulation. In some states, any perceived

pullback on EPA enforcement will likely increase state enforcement. While that may reduce

penalties, corrective action measures may well track prior EPA settlements. And lastly, the

various settlements reflect different approaches that companies have taken with regard to EPA

enforcement actions.

For fiscal years 2014-16, EPA conducted more than 2,100 inspections and evaluations

across the country as part of its energy extraction NEI and concluded 91 enforcement actions.43

While not all inspections result in enforcement action, of course, many of these ongoing energy-

based investigations will remain active, even with a change in Administration.

[10] Air Enforcement

EPA’s energy extraction enforcement initiative resulted in one 2015 landmark air case:

the settlement with Noble Energy, Inc. EPA, DOJ, and the State of Colorado’s spring 2015

settlement with Noble sent shockwaves through the industry due in large part to its size: over $73

million in total estimated costs, including a $4.95 million civil penalty.44 Most notable was the

scope (and cost) of the injunctive relief. EPA demanded and received agreement from Noble to

implement more advanced technologies and practices than were required by any applicable rule

or regulation. EPA projected that implementation of the injunctive relief actions, addressing

3,400 tank batteries, would cost Noble approximately $60 million and reduce VOC emissions by

43 Chart, U.S. Environmental Protection Agency, Annual Number of EPA Energy Extraction

Inspections/Evaluations and Concluded Enforcement Actions (available online at

https://www.epa.gov/enforcement/national-enforcement-initiative-ensuring-energy-extraction-activities-comply) 44 Press Release, U.S. Environmental Protection Agency, Noble Energy Inc. agrees to make system upgrades and

fund projects to reduce air pollution in Colorado (April 22, 2015) (available online at

https://www.epa.gov/enforcement/reference-news-release-noble-energy-inc-agrees-make-system-upgrades-and-

fund-projects)

21

2,400 tons per year.45 In addition, Noble agreed to spend at least $4.5 million on environmental

mitigation projects and $4 million on supplemental environmental projects.46

In September 2015, EPA made clear that it intended to continue its upstream air

enforcement efforts by releasing a compliance alert to the industry.47 EPA stated that it and

states “have identified Clean Air Act compliance concerns regarding significant emissions from

storage vessels, such as tanks or containers, at onshore oil and natural gas production

facilities.”48 Since that time, through additional flyovers, site investigations, and the use of CAA

Section 114 requests for information, EPA has continued gathering information on upstream oil

and gas compliance efforts.

While some companies have been allowed to “find and fix” observed emissions from

storage tanks and other identified noncompliances, others have become the subject of formal

enforcement by EPA. On December 1, 2016, EPA announced a settlement with Slawson

Exploration Company, Inc. regarding what EPA charged was the “inadequate design, operation,

and maintenance of the vapor control systems” for storage tanks at Slawson’s oil and natural gas

production well pads in North Dakota, which resulted in unauthorized emissions of VOCs,

HAPs, and methane.49 Because some of the wells are located on the Fort Berthold Indian

Reservation, EPA alleged that Slawson had violated regulatory requirements in both the Fort

45 Id. 46 Id. 47 Compliance Alert, U.S. Environmental Protection Agency Office of Enforcement and Compliance Assurance,

EPA Observes Air Emissions from Controlled Storage Vessels at Onshore Oil and Natural Gas Production Facilities

(Sept. 2015) (available online at https://www.epa.gov/sites/production/files/2015-

09/documents/oilgascompliancealert.pdf) 48 Id.at 1 49 Press Release, U.S. Environmental Protection Agency, Slawson Exploration Company, Inc. Clean Air Act

Settlement (Dec. 1, 2016) (available online at https://www.epa.gov/enforcement/slawson-exploration-company-inc-

clean-air-act-settlement); Consent Decree at 4-5, U.S. v. Slawson Exploration Company, Inc., 1:16-CV-413 (D.N.D.

Dec. 1, 2016) ECF No. 4-1 (available online at https://www.epa.gov/sites/production/files/2016-12/documents/cd-

559321-slawson-exploration-caa.pdf) (hereinafter “Slawson”)

22

Berthold Indian Reservation Federal Implementation Plan (FIP) and the North Dakota State

Implementation Plan (SIP).50

The settlement, which arose from 2014 site inspections followed by Section 114

information requests, covers all 170 of Slawson’s well pads in North Dakota that have wells

currently in production.51 In addition to allegations surrounding the storage tanks and associated

control devices, EPA inspectors also alleged that pit flares were being used at well pads located

on the reservation for more than 90 days from the first date of production of the associated wells

and that there were problems with their operations.52

Slawson paid a $2.1 million civil penalty to the United States.53 Unlike Noble, where the

State of Colorado was involved in the enforcement action and received part of the civil penalty

payment,54 neither the State of North Dakota, nor a representative of the Fort Berthold Indian

Reservation participated in the enforcement and will not receive any payment. This is the first

significant EPA oil and gas storage tank/air emissions enforcement settlement since Noble.

As with Noble, the Slawson settlement agreement mandates the implementation of extra-

regulatory technologies and practices as injunctive relief, going beyond what is required in NSPS

OOOO and OOOOa. In fact, the Slawson agreement is nearly identical to the relief obtained by

EPA in Noble. Both require:

50 Slawson at 2 51 Slawson at 5; Press Release, U.S. Environmental Protection Agency, Slawson Exploration Company, Inc. Clean

Air Act Settlement (Dec. 1, 2016) (available online at https://www.epa.gov/enforcement/slawson-exploration-

company-inc-clean-air-act-settlement) 52 Slawson at 1 53 Press Release, U.S. Environmental Protection Agency, Slawson Exploration Company, Inc. Clean Air Act

Settlement (Dec. 1, 2016) (available online at https://www.epa.gov/enforcement/slawson-exploration-company-inc-

clean-air-act-settlement) 54 See Consent Decree, U.S. and the State of Colorado v. Noble Energy, Inc. 1:15-CV-00841 (D.Co. Apr. 22, 2015)

ECF No. 2-1 (available online at https://www.epa.gov/sites/production/files/2015-04/documents/noble-cd.pdf)

(hereinafter “Noble”).

23

the development of modeling guidelines to determine potential peak

instantaneous vapor flow rates, and the completion of engineering design

standards to ensure vapor control systems are properly designed and sized

to control VOC emissions;55

After conducting a field survey, application of appropriate engineering

design standards to determine if tank systems are properly designed and to

make any necessary modifications to meet those standards;56

performance of infrared camera inspections pursuant to an EPA-approved

procedure to ensure that vapor control systems are working and tanks are

not emitting VOCs;57 and

implementation of a directed inspection and preventative maintenance

program approved by EPA to ensure the upkeep and continued operation

of the control systems.58

Once required work is completed, Slawson must hire an independent third-party auditor

to review in-house engineering evaluations and perform additional infrared camera inspections

of vapor control systems. Depending on those results, root cause analyses may be required to

determine appropriate responses.59 Moreover, after conducting periodic inspections, Slawson is

required to take necessary corrective action or, except in limited circumstances, temporarily shut-

in production associated with a failing tank system within five days.60

55 Slawson at 13-15, Noble at 15-18 56 Slawson at 17-19, Noble at 18-20 57 Id. 58 Slawson at 21-23, Noble at 24-26 59 Slawson at 29-32, 29-33 60 Slawson at 27

24

In addition, Slawson is required to install Next Generation pressure monitors with

continuous data logging on a representative sample of its tanks and verify that they are not

experiencing increased pressure readings indicative of tank over-pressurization that could cause

VOC emissions.61 Electronic tank pressure monitors are required on the tank systems that

receive produced oil from one or more of Slawson’s top 20% highest producing wells.62 This

includes 60 tank batteries, 58 of which are on the Fort Berthold Indian Reservation.63 In

addition, analog monitors are required on 50% of the tank systems covered by the decree.64

Finally, Slawson is required to replace all pit flares being used to control storage tank

emissions in North Dakota with a control device capable of achieving a 98 percent control

efficiency and is not to use pit flares to control emissions from any storage tank at a tank system

covered by the settlement.65

In total, EPA expects that implementation of the injunctive relief actions will cost

Slawson $4.1 million and reduce emissions by over 11,700 tons per year of VOCs, 400 tons per

year of HAPs, and 2,600 tons per year of methane.66

Slawson is also required to complete mitigation projects as part of the settlement. The

company will install $1.5 million in equipment to allow for auto-gauging of storage tanks so as

to decrease the need to open thief hatches.67 In addition, Slawson agreed to alter the manner in

which the company powers its drilling rigs to reduce emissions, using one of three options:

electrification, using a selective catalytic reduction module as an add-on control for the drill rig

61 Slawson at 33-35, Noble at 33-36 62 Slawson at 33-34 63 Slawson at 73-79 64 Slawson at 32-33 65 Slawson at 16, 29 66 Press Release, U.S. Environmental Protection Agency, Slawson Exploration Company, Inc. Clean Air Act

Settlement (Dec. 1, 2016) (available online at https://www.epa.gov/enforcement/slawson-exploration-company-inc-

clean-air-act-settlement) 67 Slawson at 82

25

exhaust, or retrofitting the engines.68 Slawson estimates that it will cost $550,000 per rig to

make these modifications.69 These projects must be completed by the end of 2017.70

One requirement from the Noble settlement that is conspicuously absent in

Slawson is the requirement that Noble sponsor a study to identify protocols for improved

reliability of sampling and analysis of pressurized liquids or improve data accuracy in modeling

flashing losses at condensate tanks.71 EPA intended for the study to provide other companies

with the opportunity to learn from Noble’s findings and apply them to their own storage tanks,

which EPA hoped would help reduce emissions.72 Evidently, EPA feels that adequate

information is now available to companies and that appropriate reviews and corrective measures

should already have been implemented.

[11] Oil Spill Enforcement

The settlements with Noble and Slawson were large, but are smaller than the settlements

obtained in recent oil spill cases. One in particular from the midstream sector stands out: EPA’s

July 26, 2016 $177 million final settlement with Enbridge Energy Limited Partnership and

several related Enbridge companies resolving claims from oil spills in Marshall, Michigan and

Romeoville, Illinois that occurred in 2010.73

68 Id. at 82-83 69 Id. at 83-84 70 Id. at 82-84 71 Noble at 40-41, see also Noble at 153 (Appendix D, describing study parameters) 72 Press Release, U.S. Environmental Protection Agency, Noble Energy, Inc. Settlement (April 22, 2015) (available

online at https://www.epa.gov/enforcement/noble-energy-inc-settlement) 73 Press Release, U.S. Environmental Protection Agency, United States, Enbridge Reach $177 Million Settlement

after 2010 Oil Spills in Michigan and Illinois (July 20, 2016) (available online at

https://www.epa.gov/newsreleases/united-states-enbridge-reach-177-million-settlement-after-2010-oil-spills-

michigan-and)

26

The first spill occurred near Marshall, Michigan. Over the course of two days 20,082

barrels of oil flowed from a rupture in Line 6B of Enbridge’s Lakehead System.74 The Lakehead

System is a complex of 14 pipelines that span 1,900 miles from the international border near

Neche, North Dakota to delivery points in the Midwest, New York, and Ontario.75 EPA alleged

that despite several alarms sounding in Enbridge’s control room, Enbridge did not realize for 17

hours that the pipeline had ruptured.76 EPA further allege that Enbridge restarted the faulty line

on two occasions the day after the rupture.77 Then, heavy rains caused the Kalamazoo River to

overrun its banks, spreading the discharged oil into the river’s flood plains.78 The spill caused

the Kalamazoo River to be closed in places over a three year period, and necessitated the

dredging of sections of the river.79 The second spill occurred two months later, near Romeoville,

Illinois, when Line 6A began to leak, ultimately discharging 6,427 barrels into tributaries of the

Des Plaines River.80 A National Transportation Safety Board pipeline accident brief determined

that the probable cause of the Line 6A leak was water impingement from an improperly installed

third-party owned water pipe located just below Line 6A.81

After the 2010 spills, Enbridge agreed to replace Line 6B in its entirety, rather than

repairing it.82 The new 285-mile pipeline stretches from Griffith, Indiana to the international

74 Consent Decree at 1-2, U.S. v Enbridge Energy Limited Partnership, et al., 1:16-CV-914 (W.D Mich. July 20,

2016) ECF No. 3 (available online at https://www.epa.gov/sites/production/files/2016-07/documents/enbridge-

cd.pdf ) (hereinafter “Enbridge”) 75 Id. at 1 76 Press Release, U.S. Environmental Protection Agency, Reference News Release: U.S., Enbridge Reach $177

Million Settlement after 2010 Oil Spills in Michigan and Illinois (July 20, 2016) (available online at

https://www.epa.gov/enforcement/reference-news-release-us-enbridge-reach-177-million-settlement-after-2010-oil-

spills) 77 Id. 78 Id. 79 Id. 80 Enbridge at 2, 4 81 Id. at 4-5 82 Id. at 5

27

border near Sarnia, Ontario.83 Enbridge also made a series of changes to its processes in order to

reduce the potential for future oil discharges from the Lakehead System.84 Among other things,

Enbridge developed and implemented its “Lakehead Plan,” which sets out specific safety

improvements to particular pipelines within the system, including procedures for ongoing

inspection, replacement, and testing of its lines.85 The plan, which was developed pursuant to a

corrective order issued by the U.S. Department of Transportation Pipeline and Hazardous

Materials Safety Administration (PHMSA), also set timelines for the work.86

On its other pipelines, Enbridge substantially expanded and improved upon its use of in-

line inspection (“ILI”) technology to root out cracks or corrosion that needs to be excavated or

repaired.87 Between the time of the spill and September 2014 Enbridge completed 180 ILI runs,

resulting in 5,700 excavations.88 Enbridge also purchased 55 new remotely controlled valves.89

Enbridge has spent $50 million since the 2010 spills to improve its emergency response

systems.90 As part of that effort, in September 2015, hundreds of personnel from Enbridge, EPA,

the U.S. Coast Guard, state, and local officials conducted a full-scale exercise to test their

processes.91 Enbridge also:

Revised its Integrated Contingency Plans, which were approved by

PHMSA;92

Developed tactical response plans for key points in the Lakehead

System;93

83 Id. 84 Id. 85 Id. 86 Id. 87 Id. at 5-6 88 Id. 89 Id. at 8 90 Id. at 6 91 Id. 92 Id. at 7

28

Implemented spill response training recommended by the U.S. Federal

Emergency Management Agency;94

Purchased additional emergency response equipment, including incident

command post trailers, decontamination trailers, work boats, submerged

oil trailers, and portable dam systems;95

Hired 20 new emergency response staff, as part of an overall

reorganization of the department;96 and

Conducted outreach to the public to help people be better informed

regarding leak warning signs and other potential hazards.97

As part of its reorganization of its emergency response and safety systems, Enbridge created a

new Operations and Integrity Committee and Safety and Reliability Committee.98 Senior

executives participate in both committees.99 Enbridge also created a new Vice President of

Enterprise Safety and Operational Reliability.100 And it established a Pipeline Control

department, with increased staffing dedicated to leak detection.101

While Enbridge was responding to the 2010 spills, it encountered another rupture near

Grand Marsh, Wisconsin.102 In response, PHMSA ordered Enbridge to complete hydrostatic

93 Id. 94 Id. 95 Id. 96 Id. 97 Id at 8 98 Id. 99 Id. 100 Id. 101 Id. 102 Id. at 6

29

pressure testing of that part of the pipeline.103 Enbridge then completed additional hydrostatic

pressure testing to confirm the integrity of other portions of the Lakehead System.104

Enbridge paid $62 million in civil penalties for Clean Water Act violations—$61 million

for discharging 20,082 barrels of oil near Marshall and $1 million for discharging 6,427 barrels

of oil in Romeoville.105 (That breaks down to $155.60 per barrel for the Romeoville spill, and

$3,037.55 per barrel for the spill near Marshall.)

In addition to civil penalties and the cost of implementing injunctive relief, Enbridge was

also required to reimburse the government over $5.4 million for cleanup costs and commit to

paying future removal costs incurred by the government.106 That commitment, which resolved

Enbridge’s liability under the Oil Pollution Act, came on top of the $58.5 million Enbridge had

already reimbursed the government for other cleanup costs.107 Indeed in its press release

announcing the settlement, EPA claimed that “Enbridge reportedly incurred costs in excess of $1

billion for required cleanup activities relating to the Marshall and Romeoville spills.”108

The bulk of the final settlement, $110 million, is earmarked for a series of actions

designed to prevent future spills. Among other things, Enbridge agreed to:

Conduct periodic ILI runs of each pipeline using tools that are most appropriate

for accurately detecting, characterizing and sizing all cracks, corrosion, and

geometric features that are present or anticipated on the particular pipeline being

inspected.109 Enbridge is to then use the information gleaned from these

103 Id. 104 Id. 105 Press Release, U.S. Environmental Protection Agency, United States, Enbridge Reach $177 Million Settlement

after 2010 Oil Spills in Michigan and Illinois (July 20, 2016) (available at https://www.epa.gov/newsreleases/united-

states-enbridge-reach-177-million-settlement-after-2010-oil-spills-michigan-and) 106 Id. 107 Id. 108 Id. 109 Enbridge at 31

30

inspections as the basis for regular repairs and improvements on the pipelines.110

EPA sets out highly detailed specifications, including criteria for ranking types of

damage and spelling out timeframes for repairs based on each incident of

damage’s location;111

Implement additional measures to prevent spills in the Straits of Mackinac, the

narrow stretch of water that connects Lake Huron to Lake Michigan.112 These

measures include a one time biota inspection, which requires Enbridge to conduct

underwater visual inspection of its pipelines to determine whether biota such as

mussels are impacting pipeline integrity.113 Enbridge must then report its findings

to EPA, which will then approve or disapprove a proposed work plan;114

Develop and maintain a database to integrate data from in-line inspections with

other field measurements;115

Prepare and submit to EPA a report regarding the feasibility and performance of

certain new leak detection technologies;116

Improve spill response and preparedness and improve coordination with

government planners;117

Hire an independent third party to assist with consent decree compliance

verification;118 and

Submit semi-annual status reports.119

110 Id. at 33-38 111 Id. 112 Id. at 75 113 Id. at 77-78 114 Id. at 78 115 Id. at 81 116 Id. at 84 117 Id. at 111 118 Id. at 127

31

Enbridge is enjoined from using the old Line 6B, the line where the Michigan spill occurred (and

which it replaced).120 It must also replace another line, which runs approximately 292 miles, and

evaluate the replacement of a third.121

The Enbridge settlement sets out required injunctive relief in far greater detail than two

other recent settlements, those between EPA and the State of Arkansas and ExxonMobil Pipeline

Company,122 and between EPA and Sunoco Pipeline L.P.123

In ExxonMobil’s case, its 20-inch-diameter “Pegasus Pipeline” ruptured near Mayflower,

Arkansas in March 2013, spilling 3,190 barrels of crude oil into a suburban subdivision and Lake

Conway.124 Twenty-one homes were ordered evacuated as a result of the spill.125 Wetland

vegetation, waterfowl and various other wildlife were impacted.126

In its April 22, 2015 consent decree with EPA and the State of Arkansas, ExxonMobil

agreed to idle the Pegasus Pipeline until it had been brought into compliance with a PHMSA

Corrective Action order issued shortly after the spill.127 Before restarting the pipeline,

ExxonMobil stated that it would conduct a “spike” hydrotest as part of an 8-hour sustained

pressure test and analyze its 2010 and 2013 in-line inspection results with a process to help

detect anomalies related to long-seam failure (a “KMAP” analysis).128

119 Id. at 138 120 Id. at 25 121 Id. at 25-28 122 Consent Decree, U.S. and State of Arkansas v ExxonMobil Pipeline Company and Mobil Pipe Line Company,

4:13-CV-0355 (E.D Ark. April 22, 2015) (available online at https://www.epa.gov/sites/production/files/2015-

04/documents/exxonmobil-cd.pdf) (hereinafter “ExxonMobil”) 123 Consent Decree, U.S. v Sunoco Pipeline L.P., (S.D.T.X. July 11, 2016) (available online at

https://www.epa.gov/sites/production/files/2016-07/documents/sunocopipelinelp-cd.pdf) (hereinafter “Sunoco”) 124 ExxonMobil at 1-2 125 Press Release, U.S. Environmental Protection Agency, ExxonMobil Mayflower Clean Water Settlement (April

22, 2015) (available online at https://www.epa.gov/enforcement/exxonmobil-mayflower-clean-water-settlement) 126 Id. 127 ExxonMobil at 2, 7-8 128 Id. at 2

32

Injunctive relief measures include treating the northern segment of the Pegasus Pipeline

(Patoka, Illinois to Corsicana, Texas) as susceptible to longitudinal seam failure (as construed by

PHMSA) in the future and agreeing to take other pipeline safety measures to help prevent future

spills.129 This includes supplemental training for its first responders and purchasing additional

spill response equipment and supplies that were cached in strategic locations along the

pipeline.130

Sunoco discharged 1,900 barrels of crude oil from a station near Mont Belvieu, Texas in

2009, and 1,742 barrels from a tank farm near Cromwell, Oklahoma in 2011.131 In response,

Sunoco made changes to its processes, starting immediately after the 2009 event. It made still

more after the 2011 spill, all recognized by EPA as being prior to entering into the consent

decree. Those process changes included:

conducting assessments at its facilities to identify potential upgrades, asset

replacements or removals, or other mitigation measures to reduce the risk of

spills;132

establishing a multi-year Facility Integrity Program to assess active and idle lines

for any risks of failure;133

establishing a dead-leg removal and line flushing program;134

conducting over 21 formal assessments of its facilities and removing, draining,

and purging approximately 29 miles of dead-leg pipe;135

129 Id. at 7-8 130 Id. at 8 131 Press Release, U.S. Environmental Protection Agency, Sunoco Pipeline, L.P. Clean Water Act Settlement (July

11, 2016) (available online at https://www.epa.gov/enforcement/sunoco-pipeline-lp-clean-water-act-settlement) 132 Sunoco at 1 133 Id. at 1-2 134 Id. at 2 135 Id.

33

establishing a “Pipeline Internal Corrosion Guideline” to establish the company’s

process for evaluating internal corrosion, identify and implement mitigation

actions, and reevaluate risks on its pipelines;136

hiring an internal corrosion specialist;137

updating the leak detection procedures at its Sugar Land, Texas control room,

including new logging requirements, data checks, and a shut-down procedure to

be applied after three hours of any unexplained volume discrepancies;138

installing LeakWarn pipeline integrity monitoring software;139 and

hiring a third party auditor to assess the Sugar Land, Texas control room leak

detection procedures and safety law compliance;140

The injunctive relief granted by the July 11, 2016 consent decree was then limited to three areas:

corrosion assessment, dead-leg piping, and control room procedures.141 Sunoco agreed to

examine in-station piping at certain facilities to determine the amount of corrosion in the lines.142

It was then required write a post-assessment action plan setting forth how it would address any

corrosion risks in the piping.143 The settlement also mandated that Sunoco continue the dead leg

removal and line flushing program it had already developed.144 Finally, Sunoco made changes at

its control room in Sugar Land, Texas to improve procedures and better identify potential

136 Id. 137 Id. 138 Id. at 3 139 Id. 140 Id. 141 Id. at 15-22 142 Id. at 15-19 143 Id. 144 Id. at 19-20

34

spills.145 The decree required that Sunoco certify to EPA that training in these procedures had

been completed by certain dates.146

ExxonMobil and Sunoco paid much smaller civil penalties on a per-barrel basis. As

noted, Enbridge paid $155.60 per barrel for the Romeoville spill, and $3,037.55 per barrel for the

spill in Marshall—the spill that impacted the Kalamazoo River. In contrast, ExxonMobil paid a

$3,190,000 federal civil penalty for 3,190 barrels and an additional $1,000,000 in civil penalties

to the State of Arkansas147 for a total of $1,313.48 per barrel. Sunoco paid less: an $850,000

federal civil penalty for 3,642 barrels, a rate of $233.39 per barrel.

[12] Damage to Wetlands Enforcement

EPA’s initiative also encompasses wetlands damage cases. Two cases settled in 2014—

both involving the State of West Virginia—demonstrate EPA’s current approach to wetlands

cases. On September 2, 2014, Trans Energy, Inc. entered into a consent decree with EPA and the

West Virginia Department of Environmental Protection to resolve violations of Sections 301(a)

and 404 of the Clean Water Act (CWA), 33 U.S.C. §§ 1311(a) and 134.148 Trans Energy agreed

to pay a civil penalty of $3 million, divided equally between the United States and West

Virginia.149 Then, on December 22, 2014, XTO Energy, Inc., a subsidiary of ExxonMobil,

entered into a similar consent decree resolving violations of the same federal and state laws.150

145 Id. at 20-22 146 Id. 147 ExxonMobil at 5-6 148 Press Release, U.S. Environmental Protection Agency, Trans Energy, Inc. Clean Water Act Settlement

(September 2, 2014) (available online at https://www.epa.gov/enforcement/trans-energy-inc-clean-water-act-

settlement) 149 Consent Decree at 13-14, U.S. and the State of West Virginia v Trans Energy Inc., (N.D.W. Va. Sept. 2, 2014)

(available online at https://www.epa.gov/sites/production/files/2014-09/documents/transenergyinc.pdf) (hereinafter

“Trans Energy”) 150 Press Release, U.S. Environmental Protection Agency, XTO Energy, Inc. Settlement - 2014 (December 22, 2014)

(available online at https://www.epa.gov/enforcement/xto-energy-inc-settlement-2014)

35

XTO agreed to pay a civil penalty of $2.3 million, also divided between the United States and

West Virginia.151

The Trans Energy and XTO cases involved the discharge of dredged and/or fill material

during the construction of natural gas extraction facilities, including well pads.152 For Trans

Energy, discharges also occurred at impoundments, road crossings and pipeline crossings; for

XTO, at freshwater pits, access roads, a pipeline, and a compressor station pad.153 The

discharges at Trans Energy’s facilities impacted approximately 13,000 linear feet of stream and

1.329 acres of wetlands at 15 sites, while the discharges at XTO’s facilities impacted

approximately 5,357 linear feet of stream and 3.38 acres of wetlands across eight sites in West

Virginia.154

Both cases arose after EPA discovered the violations through information provided to the

public, and through routine field inspections.155 Each company then conducted internal audits

and disclosed additional violations to EPA.156 The injunctive relief in each case is nearly

identical. Each company was required to:

restore all sites where feasible, or complete appropriate compensatory mitigation

where restoration is not feasible;157

151 Consent Decree at 9-10, U.S. and the State of West Virginia v XTO Energy Inc., (N.D.W. Va. Dec. 22, 2014)

(available online at https://www.epa.gov/sites/production/files/2014-12/documents/xto-cd14.pdf) (hereinafter

“XTO”) 152 Id. 153 Id. 154 Id. 155 Press Release, U.S. Environmental Protection Agency, Trans Energy Inc. to Restore Streams and Wetland

Damaged By Natural Gas Extraction Activities in West Virginia/ Company will also pay $3 million civil penalty to

resolve alleged Clean Water Act violations (September 2, 2014) (available online at

https://yosemite.epa.gov/opa/admpress.nsf/bd4379a92ceceeac8525735900400c27/84ad6a5e4f32adf985257d470072

7291); Press Release, U.S. Environmental Protection Agency, XTO Energy, Inc. to Restore Areas Damaged by

Natural Gas Extraction Activities (December 22, 2014) (available online at

https://yosemite.epa.gov/opa/admpress.nsf/bd4379a92ceceeac8525735900400c27/7dd39f3df4688e3e85257db60076

ebc2!OpenDocument) 156 Id. 157 Trans Energy at 15-18, XTO at 11-15

36

develop and implement for a period of five years a CWA employee training

program;158 and

develop and implement an operational protocol to be used in West Virginia to

assure compliance with Section 404 of the CWA.159

A restoration work plan was attached to each consent decree setting out the manner in which

such restoration is to occur.160 Each party was required to submit to EPA a proposed restoration

plan for each site, and must monitor all sites for at least five years.161 Each party was also

required to record a conservation easement for the affected sites it owns and attempt to obtain

such an easement for those it leases, naming EPA, the U.S. Army Corps of Engineers, and the

West Virginia Department of Natural Resources as third-party beneficiaries.162

As part of the operational protocol, each party is required to retain a qualified wetlands

professional to assess aquatic resources within any proposed limit of disturbance and within 100

– 300 horizontal feet of any proposed limit of disturbance prior to the submission of any

application for new or expansive construction of well pads or impoundments, or any other

construction activity beyond the company’s currently approved limit of disturbance.163 In each

case, the company must (1) prepare an alternatives analysis (2) design any new facilities to avoid

and minimize their impact on aquatic resources; and (3) use construction techniques certified by

a registered professional engineer to ensure rapid stabilization of disturbed earth while assuring

erosion and sediment controls are consistent with state or local requirements.164

158 Trans Energy at 18-19, XTO at 15-16 159 Trans Energy at 23-26, XTO at 18-22 160 Trans Energy at 49 (Appendix B), XTO at 49 (Appendix A) 161 Trans Energy at 49-52, XTO at 49-51 162 Trans Energy at 15-18, XTO at 12-14 163 Id. 164 Id.

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EPA’s February 4, 2014 settlement with Gasco Energy, Inc., a natural gas exploration

and production company based in Denver, unfolded differently. Back in 2011, EPA had issued a

compliance order to Gasco, after it determined that Gasco’s natural gas production activities in

Utah had resulted in the discharge of dredged and/or fill material to wetlands subject to federal

regulation under the Clean Water Act.165 In 2012, Gasco filed suit against EPA alleging that the

compliance order was arbitrary and capricious because the preliminary jurisdictional

determination that US Army Corp of Engineers issued failed to comply with the applicable

standards for delineating wetlands and was not supported by substantial evidence.166 Its petition

sought review of final agency action under the Administrative Procedure Act, and asked the

court to set aside the compliance order.167 EPA and the Southern Utah Wilderness Alliance,

which had intervened, then filed counterclaims against Gasco, alleging that the company had

violated Sections 301(a) and 309 of the Clean Water Act and failed to comply with the terms of

the compliance order.168 The parties ultimately entered into the 2014 consent decree.169

Gasco agreed to pay a $110,000 civil penalty to the United States.170 A restoration and

monitoring plan was incorporated into the consent decree in an appendix.171 Among the tasks

Gasco was required to complete were plugging and abandoning the well at issue, removing the

fill material from a well pad and its access road, and the wetlands surrounding another well’s

access road, and placing a bottomless culvert at those wetlands to avoid and minimize wetland

165 Consent Decree at 2, Gasco Energy, Inc. v. Environmental Protection Agency and Southern Utah Wilderness

Alliance, 1:12-cv-01658 (D.Co. Feb. 2, 2014) ECF No. 79-1 (available online at

https://www.epa.gov/sites/production/files/2014-12/documents/xto-cd14.pdf) (hereinafter “Gasco”) 166 Id. 167 Id. 168 Id. at 3 169 Id. at 6-8 170 Id. at 8 171 Id. at 9, 25

38

impacts.172 Gasco was also required to monitor the site for at least five growing seasons, and

then not mow, cut, clear, cultivate, dredge, excavate, farm, fill, dewater, drain or otherwise

disturb the restoration except with consultation and approval of EPA.173

EPA’s 2015 settlement with Newfield Production Company, a Texas-based crude oil and

natural gas exploration company, also followed an unusual path to settlement.174 In 2012,

Newfield performed a voluntary audit of its CWA compliance at some of its oil and gas facilities

in Utah’s Central Basin.175 The audit found potential non-compliance at 19 facilities, including

discharges of dredged or fill material to wetlands and drainages without a CWA Section 404

permit.176 On June 1, 2012, Newfield provided a copy of the audit to the U.S. Army Corps of

Engineers, pursuant to the EPA Self-Audit Policy, 65 Fed. Reg. 19,618 (April 11, 2000), and the

Memorandum of Agreement Between the Department of the Army and the Environmental

Protection Agency Concerning Federal Enforcement of the Section 404 Program of the Clean

Water Act dated January 19, 1989.177 Newfield did not provide a copy of the audit to EPA, but

in its communication with the Corps stated that it understood that the Corps would advise if the

audit needed to be forwarded to the EPA.178 Three months later, EPA and the Corps inspected

the 19 facilities identified in the audit.179 The Corps then made a preliminary determination that

the impacted wetlands and drainages may be waters of the United States.180 On January 24,

2013, the Corps sent a notice of violation to Newfield, alleging that it had discharged dredged or

172 Id. at 28 173 Id. at 36-37, 9 174 Combined Complaint and Consent Agreement, In re: Newfield Production Company, E.P.A. CWA-08-2015-

0008 (Dec. 17, 2014) (available online at

https://yosemite.epa.gov/OA/RHC/EPAAdmin.nsf/Filings/67D3F5E009C0582185257DDB00214115/$File/CWA08

20150008%20CAFO.pdf) (hereinafter “Newfield”) 175 Id. at 2 176 Id. 177 Id. at 3 178 Id. 179 Id. 180 Id.

39

fill material into waters of the United States, including wetlands, in violation of the CWA.181

The Corps then referred the matter to EPA for enforcement.182 Pursuant to a February 2, 2015

Administrative Order on Consent, Newfield paid a $175,000 civil penalty and restored

approximately 13 acres of impacted wetlands and streams and performed mitigation for the

remaining impacts by creating ten acres of new wetlands.183

[13] Risk Management Program Enforcement

EPA, in particular EPA Region 6, has been increasing the number of Risk Management

Program184 (RMP) inspections it conducts over the past few years. In addition, incidents that

result in explosions and fires are now commonly found to be in violation of the RMP General

Duty Clause in Section 112(r)(1) of the Clean Air Act. The General Duty Clause provides that:

The owners and operators of stationary sources producing, processing, handling

or storing such substances [i.e., a chemical in 40 CFR part 68 or any other

extremely hazardous substance] have a general duty [in the same manner and to

the same extent as the general duty clause in the Occupational Safety and Health

Act (OSHA)] to identify hazards which may result from such releases using

appropriate hazard assessment techniques, to design and maintain a safe facility

taking such steps as are necessary to prevent releases, and to minimize the

consequences of accidental releases which do occur.185

181 Id. 182 Id. 183 Id. at 5; Combined Complaint and Consent Agreement at 6-10, , In re: Newfield Production Company, E.P.A.

CWA-08-2015-0007 (Dec. 17, 2014) (available online at

https://yosemite.epa.gov/OA/RHC/EPAAdmin.nsf/Filings/A2F551AD24EF599485257DB8002141FE/$File/CWA0

820150007%20AOC.pdf); Press Release, Newfield Production agrees to resolve alleged wetlands violations at

production sites in Uintah and Duchesne counties (Utah) (Feb. 2, 2015) (available online at

https://www.epa.gov/newsreleases/newfield-production-agrees-resolve-alleged-wetlands-violations-production-

sites-uintah) 184 42 U.S.C. § 7412 (r)(1) 185 Id.

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Companies can be found to be in violation of the RMP General Duty clause even if they are not

subject to the Risk Management Plan requirements found in 40 CFR Part 68.

Examples of the types of incidents that have resulted in Section 112(r)(1) General Duty

enforcement include fires and explosions at tank batteries (one caused by a welding arc igniting

vapors,186 another caused by a forklift being driven over piping,187 and still another by metal-to-

metal contact at a storage tank188). Natural gas processing plant fires have also been found to be

violations of the RMP General Duty clause. At those plants, one fire was caused by

overpressuring a closed line, causing it to rupture.189 Another was caused by a contractor

spraying water into a tank, causing a pyrophoric reaction.190

Common themes among these events are fires, operator error, and relatively low penalties

(typically in the $30,000 to $40,000 range).191 These cases are typically brought by EPA

regional offices and are resolved by a Consent Agreement and Final Order (CAFO), without

involvement by the Department of Justice.192 Settlement of an RMP case does not shield a

company for other enforcement associated with the event, such as enforcement from

unauthorized emissions, or from OSHA enforcement.193 Rather, they are additive and intended

to help drive behavioral changes within the industry.

Enforcement arising from RMP inspections at sites subject to Risk Management Plan

requirements typically result in higher penalties. In Region 5, EPA fined a company with a gas

processing facility almost $50,000 for multiple RMP programmatic violations and required

$285,000 in supplemental environmental projects (SEPs), including purchasing gas monitors for

186 GeoSouthern Energy Corporation, E.P.A. CAA-06-2015-3305 (2015) at 3 187 Alta Mesa Services, LP, E.P.A. CAA-06-2015-3304 at 3 188 Jay-Bee Oil and Gas, Inc., E.P.A. CAA-03-2015-0110 at 5 189 SemGas, LP, E.P.A. CAA-06-2016-3385 at 3 190 Enterprise Products Operating, LLC, E.P.A. CAA-06-2015-3307 at 3 191 See supra. 192 Id. 193 Id.

41

fire departments, purchasing public warning sirens, and paying for FCC licensing to authorize

new base stations to fill in a signal gap needed to facilitate communications in the event of an

emergency.194 While the facts are not clear in the CAFO, it appears that the company submitted

an initial RMP plan as required, but subsequently failed to follow its requirements and to update

the plan as needed.195

Also in 2015 EPA Region 6 assessed a $378,215 penalty and $22,000 worth of SEPs

against a company with multiple operations in Mont Belvieu, Texas.196 The SEPs benefitted the

local fire department (requiring the purchase of voice amplifiers for self-contained breathing

apparatuses and hydraulic tools to assist with rescues from collapsed, small confined spaces).197

The settlement arose from a 2011 RMP inspection after an earlier incident at the plant.198 In

addition to the penalty amount, this enforcement case is notable because of the nature of the

alleged findings: failure to identify the names or positions of persons responsible for

implementing individual requirements of Part 68 (the named individuals had moved to other

roles),199 failure to timely inspect and/or test certain process equipment,200 failure to timely

correct deficiencies in OSHA Process Safety Management (PSM) compliance audits (2007 and

2010 audits, not corrected by 2012),201 and failure to comply with Title V certification reporting

(for failure to identify the afore-mentioned omissions as deviations in the Title V report

submitted for the site).202 Similar violations were alleged after an inspection at a West Texas

194 BreitBurn Energy Partners L.P., E.P.A. CAA-05-2014-0027 at 8-15 195 Id. at 7-8 196 Enterprise Products Operating, L.L.C., E.P.A. CAA-06-2015-3315 at 12, 15 197 Id. at 15 198 Id. at 5 199 Id. 200 Id. at 6 201 Id. at 7-8 202 Id. at 8

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natural gas plant.203 In that instance, EPA Region 6 collected a $141,525 penalty—all for

relatively small violations.204 Given the relatively high penalties and simple nature of the needed

corrections to RMP plans, companies with such plans would be well served to review and update

them as needed to avoid similar outcomes.

§21.04 CONCLUSION

While forecasting the future is always risky, it seems safe to state that upstream and

midstream industry environmental issues will continue to be the subject of increased scrutiny.

eNGO can be expected to continue, and perhaps increase, their litigation efforts as a result of the

change in administration in Washington. EPA may eventually change some of its enforcement

priorities, but is unlikely to halt work on many of the cases it has already developed. And,

certain states may be willing to bring enforcement at a state level if they perceive widespread

noncompliance concerns. In sum, this is an area that should continue to be a focus for industry

practitioners.

203 DCP Midstream, LP, E.P.A. CAA-06-2015-3353 at 4-7 204 Id. at 8