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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
2
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
3
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)
4
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.
5
"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).
6
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).
7
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.).
8
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).
9
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).
10
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).
11
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).
12
[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).
13
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).
14
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.
15
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.
16
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.
17
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).
18
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.
37
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.
40
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
42
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