United States of America v. Coffeyville Resources Refining, et al
Filing
95
MEMORANDUM AND ORDER denying 40 Defendant's Petition for Judicial Review. Signed by District Judge Julie A. Robinson on 3/30/2022. (mam)
IN THE UNITED STATES DISTRICT COURT
FOR THE DISTRICT OF KANSAS
UNITED STATES OF AMERICA and
STATE OF KANSAS ex rel. KANSAS
DEPARTMENT OF HEALTH AND
ENVIRONMENT,
Case No. 04-1064-JAR-KGG
Plaintiffs,
v.
COFFEYVILLE RESOURCES REFINING &
MARKETING, LLC,
Defendant.
MEMORANDUM AND ORDER
Before the Court is Defendant Coffeyville Resources Refining & Marketing, LLC’s
(“CRRM”) Petition for Judicial Review (Doc. 40) of the decision by Plaintiffs United States of
America and the State of Kansas by and through the Kansas Department of Health and
Environment (“KDHE”) to demand stipulated penalties under the parties’ 2012 Consent Decree.
The Court has considered the parties’ original and supplemental briefs addressing both
“threshold” and “merits-based” issues and is prepared to rule. As described more fully below,
Defendant’s petition is denied to the extent it asks the Court to dismiss or reduce Plaintiffs’
stipulated penalty demand.
I.
Factual and Procedural Background
Defendant owns and operates a petroleum refinery located in Coffeyville, Kansas
(“Refinery”). The Refinery processes crude oil into refined petroleum products, including
propane, gasoline, distillates, and petroleum coke. Among numerous process units at the
Refinery are the following three flares: the Coker flare (“Coker Flare”), cold water pond flare
(“CWP Flare”), and an alky flare. Flares are open air combustion devices that destroy refinery
waste gas, resulting in emissions of various air pollutants including sulfur dioxide (“SO2”).
Defendant purchased the Refinery from the Farmland Industries’ bankruptcy estate in
2004. Immediately prior to the purchase, Plaintiffs entered into a Consent Decree with
Defendant (“2004 CD”) that resolved some, but not all, Clean Air Act (“CAA”) violations at the
Refinery.1 In 2012, Plaintiffs and Defendant entered into the Second Consent Decree (“2012
CD”) under the Environmental Protection Agency’s (“EPA”) National Petroleum Refining
Initiative (“NPRI”), which sought to reduce emissions and “level the playing field” across all
American refineries.2 The 2012 CD contains a provision for stipulated civil penalties that
Defendant must pay for “each failure to comply with the terms of this Consent Decree.”3
The 2012 CD requires, inter alia, that CRRM comply with Subparts J4 and Ja5 of the
New Source Performance Standards (“NSPS”)—regulations promulgated by the EPA pursuant to
Section 111 of the CAA. Paragraph 60 requires Defendant to comply with Subpart J; paragraph
61 requires Defendant to comply with Subpart Ja if, prior to termination, a flare becomes subject
to Subpart Ja. The parties do not dispute that by November 11, 2015, Subpart Ja applied to the
CWP and Coker Flares and that Defendant was required to comply with it in lieu of Subpart J
thereafter.
Both subparts impose requirements for refinery flares in order to protect public health
and the environment, including limiting hydrogen sulfide (“H2S”) concentration in the gas that is
1
Doc. 8.
2
Doc. 14.
3
Id. ¶ 180.a.
4
40 C.F.R. § 60.100, et seq.
5
40 C.F.R. § 60.100a, et seq.
2
flared. When combusted, H2S forms SO2, compromising respiratory health, harming vegetation,
and decreasing plant growth. The regulations also require refineries to monitor the H2S
concentration in the gas being flared. Subpart Ja requires monitoring of other parameters
including gas flow to each flare, performance tests and evaluations of monitoring equipment,
adherence to monitoring equipment quality assurance and calibrations requirements, and
submission of flare management plans to EPA.
On June 19, 2020, pursuant to paragraph 202 of the 2012 CD, Plaintiffs demanded
stipulated penalties from Defendant under the 2012 CD for twenty-four different violations,
eighteen of which were violations of Subparts J and Ja requirements. The parties engaged in
informal dispute resolution as required under the 2012 CD. On January 8, 2021, after
unsuccessful attempts to resolve the disputes informally, Plaintiffs sent Defendant a written
notice ceasing informal dispute resolution in accordance with the 2012 CD. Plaintiffs then
served their Statement of Position (“SOP”) on Defendant, setting forth their decision that
Defendant is liable for $6,819,600 in stipulated penalties. Defendant ceased disputing one claim
and paid $2,600 in stipulated penalties, bringing the total stipulated penalty demand to
$6,817,000.
Claims 1–2 in the SOP allege that Defendant failed to comply with paragraph 60 of the
2012 CD and Subpart J by failing to install and operate a continuous emissions monitoring
system at the Coker and CWP flares. Claims 3–18 allege that Defendant failed to comply with
paragraph 61 of the 2012 CD and various Subpart Ja requirements at the Coker and CWP flares.
In their supplemental response brief, Plaintiffs withdrew Claims 17–18.
3
Before the informal dispute resolution had concluded as to the 2012 CD, Plaintiffs filed
the First Supplemental Complaint on December 28, 2020.6 It alleged nine counts, including
violations of the CAA, Kansas Air Quality Act (“KAQA”), and regulations “based on
transactions, occurrences, and events that occurred after the filing of the original Complaint.”7
Counts 1 and 2 “are also violations of the 2012 Consent Decree,” based on exceedances of H2S
concentration limits at the Coker and CWP flares.8 On February 17, 2022, Plaintiffs filed a First
Amended Supplemental Complaint (“FASC”), adding eight more claims.9 Defendant separately
moves to dismiss the civil penalties sought by the State in all counts, Count 9 in its entirety, and
to partially dismiss Count 17.10 That motion remains pending.
The 2012 CD provides that Plaintiffs’ SOP is binding unless Defendant files a Petition
for Review within sixty days of Plaintiffs’ SOP. On April 5, 2021, Defendant timely filed its
petition requesting that the Court review the eighteen claims in the SOP for stipulated penalties
based on violations of Subparts J and Ja.11 The petition asserts four “threshold” issues for the
Court to consider and sought additional time for discovery and briefing on “merits-based” issues.
The Court denied Defendant’s motion for discovery and set a supplemental briefing schedule for
the merits-based challenges. These briefs having all been filed, Defendant’s petition is ripe for
consideration. The Court first considers Defendant’s challenges to Claims 1 and 2 based on
6
Doc. 32.
7
Id. ¶ 5.
8
Id. ¶ 7.
9
Doc. 90.
10
Doc. 91.
11
Doc. 40. The Honorable Monti L. Belot presided over this case when it was filed in 2004 and signed the
consent decrees. This case was eventually reassigned to the undersigned on May 3, 2021, after the pending motions
were filed.
4
violations of Subpart J and then proceeds to Defendant’s challenges to the remaining claims
under Subpart Ja.
II.
Standards
Defendant’s Petition for Judicial Review asks this Court to resolve the parties’ disputes
about sixteen alleged violations of the 2012 CD for which Plaintiffs demand stipulated penalties.
This Court has jurisdiction under Section XIII of the 2012 CD, which states that “[t]his Court
shall retain jurisdiction of this matter for the purposes of implementing and enforcing the terms
and conditions of the Consent Decree and for the purpose of adjudicating all disputes.”12 The
2012 CD requires the parties to comply with informal dispute resolution before bringing their
dispute to the Court. The parties have engaged in this process and Claims 1–16 remain for this
Court to address.
The parties do not address the applicable standard of review outside the context of their
previously-resolved discovery request.13 They agree that under Tenth Circuit law, “[a] consent
decree is a negotiated agreement that is entered as a judgment of the court.”14 The Court
construes a consent decree for enforcement purposes as a contract; thus, “the terms of the decree
and the respective obligations of the parties must be found within the four corners of the consent
decree.”15 The Court applies Kansas law to interpretive issues relating to the consent decree.16
12
Doc. 14 ¶ 216.
13
In the initial round of briefing, the parties focused on whether the Court should be limited to an
“administrative record” when considering the petition. The Court previously expressed its skepticism that the
Administrative Procedures Act’s standard of review applies here given that it is not provided for in the 2012 CD, but
declined to resolve the issue because it found that, even assuming the general standard set forth in Fed. R. Civ. P.
26(b) applied, discovery was not warranted. See Doc. 60 at 6.
14
Sinclair Oil Corp. v. Scherer, 7 F.3d 191, 193 (10th Cir. 1993) (citations omitted).
15
Id. (citing United States v. Armour & Co., 402 U.S. 673, 681–82 (1971)).
16
Id. (citing Air Line Stewards & Stewardesses Ass’n v. Trans World Airlines, Inc., 713 F.2d 319, 321 (7th
Cir. 1983)); Johnson v. Lodge #93 of Fraternal Order of Police, 33 F.3d 1096, 1102 (10th Cir. 2004).
5
Under Kansas law, the burden of proof in civil cases is generally proof by preponderance of the
evidence.17 Because the 2012 CD does not provide for a different standard of review, this Court
applies the preponderance standard to the parties’ factual disputes.18 Under this standard, a
“‘preponderance of the evidence’ means that evidence which shows a fact is more probably true
than not true.”19
Under Kansas law, if the language in a written contract “is clear and can be carried out as
written, there is no room for rules of construction. To be ambiguous, a contract must contain
provisions or language of doubtful or conflicting meaning, as gleaned from a natural and
reasonable interpretation of its language.”20 “In considering a contract which is unambiguous
and whose language is not doubtful or obscure, words used therein are to be given their plain,
general and common meaning, and a contract of this character is to be enforced according to its
terms.”21 “The cardinal rule of contract interpretation is that the court must ascertain the parties’
intention and give effect to that intention when legal principles so allow.”22
17
Ortega v. IBP, Inc., 874 P.2d 1188, 1192 (Kan. 1994).
18
See Sinclair Oil Corp., 7 F.3d at 193; United States v. Sanitary Dist. of Hammond, No. 2:93-CV-225JTM-PRC, 2012 WL 6599919, at *6–7 (N.D. Ind. Dec. 18, 2012) (applying APA standard of judicial review based
on the administrative record where consent decree explicitly provided for it); United States v. Minnkota Power Coop, Inc., 831 F. Supp. 2d 1109, 1118–19 (D.N.D. 2011) (applying standard of review specified in consent decree:
“The Court shall sustain the decision by NDDH unless the Party disputing the BACT Determination demonstrates
that it is not supported by the state administrative record and not reasonable in light of applicable statutory and
regulatory provisions.”); cf. United States v. Volvo Powertrain Corp., 758 F.3d 330, 147 (D.C. Cir. 2014) (finding
no error in district court’s application of preponderance standard on petition for judicial review of a consent decree
where evidentiary standard made little difference to end result, and the defendant waived it below).
19
In re B.D.-Y., 187 P.3d 594, 598 (Kan. 2008).
20
Gore v. Beren, 867 P.2d 330, 337 (Kan. 1994) (quoting Simon v. Nat’l Farmers Org., Inc., 829 P.2d 884,
Syl. ¶ 2 (Kan. 1992)).
21
Wagnon v. Slawson Expl. Co., 874 P.2d 659, 666 (Kan. 1994) (quoting Barnett v. Oliver, 858 P.2d 1228,
1238 (Kan. Ct. App. 1993)).
22
Kay-Cee Enter., Inc. v. Amoco Oil Co., 45 F. Supp. 2d 840, 843 (D. Kan. 1999) (quoting Ryco Packaging
Corp. v. Chapelle Int’l, Ltd., 926 P.2d 669, 674 (Kan. Ct. App. 1996)).
6
Defendant is required to comply with certain federal regulations under the terms of the
2012 CD; thus, some of the parties’ disputes involve regulatory interpretation. In interpreting
these regulations, the Court applies the same rules used to interpret statutes.23 The Tenth Circuit
explains:
We examine the plain language of the regulation and give each
word its ordinary and customary meaning. Thus, in determining
the plain meaning of a regulation, we do not consider the
regulatory history or anything outside the text. If the language of
the regulation is clear, we enforce the regulation in accordance
with its plain meaning, giving no deference to a contrary
interpretation by the Secretary.24
If the Court determines that a regulation is “genuinely ambiguous,” it applies Auer
deference, “defer[ring] to the agency’s construction of its own regulation.”25 But a regulation is
not genuinely ambiguous simply because it is difficult to read.26 Before concluding that a
regulation is ambiguous, the Court must first exhaust its “legal toolkit” and find that “the
interpretive question still has no single right answer.”27 This legal toolkit includes considering
“the text, structure, history, and purpose of a regulation, in all the ways [the Court] would if it
had no agency to fall back on.”28 If a genuine ambiguity remains after employing this toolkit,
the Court then considers whether the agency’s reading is “reasonable.”29 And, if reasonable, the
Court considers “whether the character and context of the agency interpretation entitles it to
23
Canyon Fuel Co. v. Sec’y of Lab., 894 F.3d 1279, 1287 (10th Cir. 2018) (quoting Mitchell v. Comm’r,
775 F.3d 1243, 1249 (10th Cir. 2015)).
24
Id. at 1287–88 (citations omitted).
25
Kisor v. Wilkie, 139 S. Ct. 2400, 2411 (2019) (discussing Auer v. Robbins, 519 U.S. 452 (1997)).
26
Id.
27
Id.
28
Id.
29
Id.
7
controlling weight.”30 For example, deference to an agency’s interpretation may be
inappropriate if it conflicts with a prior interpretation,31 or if it is a ‘“post hoc rationalizatio[n]’
advanced by an agency seeking to defend past agency action against attack.”32
With these standards in mind, the Court turns to the challenges raised by Defendant to
Plaintiffs’ stipulated penalty demands.
III.
Violations of Subpart J: SOP Claims 1 and 2
A.
Background
Paragraph 60 of the 2012 CD provides that the CWP and Coker flares are subject to
NSPS Subpart J for Fuel Gas Combustion Devices, and “CRRM shall comply with those
provisions.”33 The parties agree that the flares were subject to Subpart J from April 19, 2012,
when the 2012 CD was entered, until November 11, 2015, when they became subject to Subpart
Ja. Claims 1 and 2 relate to the location of the continuous emissions monitoring system
(“CEMS”) used to monitor the H2S concentration of fuel gas combusted in the flares, which is
required by 40 C.F.R. § 60.105(a)(3) and (4).
40 C.F.R. § 60.105(a)(3) and (4) provide in relevant part:
(a) Continuous monitoring systems shall be installed, calibrated,
maintained, and operated by the owner or operator subject to the
provisions of this subpart as follows:
....
(3) For fuel gas combustion devices subject to § 60.104(a)(1),
either an instrument for continuously monitoring and recording the
concentration by volume (dry basis, zero percent excess air) of SO2
emissions into the atmosphere or monitoring as provided in
30
Id. (citations omitted).
31
Christopher v. SmithKline Beecham Corp., 567 U.S. 142, 155 (2012) (citing Thomas Jefferson Univ. v.
Shalala, 512 U.S. 504, 515 (1994)).
32
Id. (alteration in original) (quoting Auer v. Robbins, 519 U.S. 452, 462 (1997)).
33
Doc. 14 ¶ 60.
8
paragraph (a)(4) of this section). The monitor shall include an
oxygen monitor for correcting the data for excess.
....
(4) Instead of the SO2 monitor in paragraph (a)(3) of this section
for fuel gas combustion devices subject to § 60.104(a)(1), an
instrument for continuously monitoring and recording the
concentration (dry basis) of H2S in fuel gases before being burned
in any fuel gas combustion device.
....
(ii) Fuel gas combustion devices having a common source of fuel
gas may be monitored at only one location, if monitoring at this
location accurately represents the concentration of H2S in the fuel
gas being burned.
Subpart J exempts certain gas streams from monitoring. Under subsection (a)(4)(iv),
owners and operators are not required to monitor gases exempt under § 60.104(a)(1)—“process
upset gases or fuel gas that is released to the flare as a result of relief valve leakage or other
emergency malfunctions”—and gas streams combusted in a fuel gas combustion device that are
inherently low in sulfur content. “Process upset gas” is defined as “any gas generated by a
petroleum refinery process unit as a result of start-up, shut-down, upset or malfunction.”34
Under § 60.105(b), Defendant “may demonstrate that a fuel gas stream combusted in a fuel gas
combustion device subject to § 60.104(a)(1) that is not specifically exempted in
§ 60.105(a)(4)(iv) is inherently low in sulfur.” To claim this exemption, Defendant must submit
a written application for an exemption to the EPA Administrator.35
At the time Defendant acquired the Refinery, Farmland Industries used an H2S CEMS
located immediately downstream of the Refinery’s fuel gas mix drum to monitor the H2S
34
40 C.F.R. § 60-101(e).
35
40 C.F.R. § 60-105(b)(1).
9
concentration of the Refinery fuel gas to all combustion sources. Defendant contends that
leading up to the 2012 CD, “CRRM had multiple discussions and negotiations with EPA and
KDHE . . . . [and] NSPS Subpart J was a focus of several of those discussions.”36 But the only
evidence of such discussion is a June 5, 2008 conference call between the parties that generated a
“Task List” for Defendant to complete. One such task was that “CRRM will need to check with
operations department to identify any continuous streams which are routed to a flare (or other
fuel gas combustion device) that are not monitored under NSPS J which would need an
alternative monitoring plan (AMP) or need to be re-routed. – target date: July 31, 2008.”37 EPA
chemical engineer Bill Peterson sent this task list to Defendant in order “to confirm Defendant’s
claim that all continuous streams had been re-routed away from Defendant’s flares, including the
Coker and CWP flares, and that only exempt streams pursuant to 40 C.F.R. § 60.104(a)(1) were
allowed to release to the flares.”38 Before and after this conference call, CRRM representatives
told Peterson that only exempt streams were allowed to release to the Coker and CWP flares, and
EPA relied on this representation when the parties discussed Defendant’s past liability in the
course of negotiating the 2012 CD.
In November 2015, Defendant installed new H2S, TRS, and flow monitors directly at its
flares. After installation, Defendant had issues with the flow monitors communicating data to
the Refinery’s data historian and data acquisition system, which store operating data and
information monitored by the CEMSs. Defendant engaged the flow monitors’ manufacturer to
address problems with the analog signal in 2015 and 2016. In the fall of 2015 and spring of
2016, Defendant undertook two substantial refinery-wide “turnarounds,” where the refinery units
36
Doc. 66, Ditmore Decl. ¶ 9.
37
Doc. 66-4 at 4.
38
Doc. 81, Peterson Decl. ¶ 6.
10
and equipment were shut down in order to implement capital and expense projects and perform
maintenance.
EPA received the first monitoring data from the new monitors in mid-2016, which
showed continuous high flow and high H2S concentrations well above the limit of 162 ppm,
which Plaintiffs maintain proves that non-exempt streams were routed to the Coker and CWP
flares. According to Plaintiffs’ expert, if “the waste gas burned in a flare contains a different
H2S concentration than [refinery fuel gas], the H2S monitor downstream of the fuel gas mix drum
does not accurately represent the H2S in the fuel gas burned in the flare.”39
Claims 1 and 2 of the SOP allege that the H2S monitor on the fuel gas mix drum does not
comply with NSPS Subpart J because it does not “accurately represent” the H2S concentration of
fuel gas being burned in the Coker and CWP flares.40 Plaintiffs contend that because the monitor
was located before the process units and therefore only monitored the H2S content of fuel gas
entering the process units, it did not monitor the H2S content of fuel gas generated in the process
units themselves. There are multiple connections between the process units and the flares after
the location of the monitor that were not re-routed back to the H2S monitor at the fuel gas mix
drug; therefore, the monitor did not “accurately represent” the H2S concentration of fuel gas
being burned at the flares. Plaintiffs seek $2.542 million in stipulated penalties per flare, per day
from the date of the release from liability in the 2012 CD (April 19, 2012) until November 11,
2015, when CRRM was required to comply with NSPS Subpart Ja.
CRRM disputes Claims 1 and 2 on the following grounds: (1) it did not violate Subpart
J’s monitoring requirement as a factual matter; and (2) Plaintiffs’ knowledge of the alleged
39
Doc. 80, Sahu Decl. ¶ 20.
40
See 40 C.F.R. § 60.105(a)(4)(ii).
11
violations since 2004 without compliance action prohibits it from now demanding the stipulated
penalties in Claims 1 and 2, or in the alternative, permits the Court to reduce the penalty amount.
The Court addresses these arguments in the next section.
B.
Discussion
1.
Factual Disputes Regarding Subpart J Monitoring Violations
The Coker and CWP flares are fuel gas combustion devices subject to Subpart J.41
Because Defendant used an H2S CEMS located immediately downstream of the Refinery’s fuel
gas mix drum to monitor the H2S concentration of the Refinery fuel gas to all combustion
sources, it used “an instrument for continuously monitoring and recording the concentration of
H2S in fuel gases before being burned in any fuel gas combustion device,” per § 60.105(a)(4).
Therefore, Defendant was required to operate the monitor in a location that “accurately
represents the concentration of H2S in the fuel gas being burned,” or demonstrate that an
exemption applies. According to the SOP, there were multiple connections between the process
units and the flares located after the monitor that were not re-routed back to the H2S monitor at
the fuel gas mix drum, and therefore were not monitored.
Defendant argues that Plaintiffs fail to proffer sufficient evidence of a monitoring
violation, and that any non-monitored streams were either accurately represented by the H2S
analyzer on the fuel gas mix drum or exempt from monitoring under § 60.105(a)(4)(iv).
Plaintiffs rely on the following evidence in support of their position that Defendant violated
Subpart J: (1) the discrepancy between the H2S concentrations recorded at the flares and the
monitor at the fuel gas mix drum based on data they began to receive in mid-2016; (2)
Defendant’s own description of various streams to the CWP and Coker flares as being non-
41
40 C.F.R. § 60-101(g).
12
exempt and unmonitored; and (3) that Defendant misconstrues the regulation’s definition of
“relief valve leakage” in arguing that that exemption applies to some of the streams to the flares.
Defendant argues, and Plaintiffs do not dispute, that Plaintiffs have the burden of proving
a monitoring violation under Subpart J.42 The parties also appear to agree that Defendant bears
the burden of demonstrating that an exemption to the monitoring requirement applies under
§ 60.105(a)(4)(iv). To be sure, the general rule is that while the plaintiff is required to prove a
statutory violation, the party claiming the benefit of a statutory exemption to compliance bears
the burden of proof on the exemption.43 With these burdens in mind, the Court first addresses
whether Defendant meets the “accurate representation” provision of Subpart J before turning to
the parties’ exemption arguments.
a.
Accurate Representation under § 60.105(a)(4)(ii)
Defendant first argues that Plaintiffs fail to demonstrate that on each day between April
20, 2012 and November 11, 2015, Defendant’s monitor at the fuel gas mix drum did not
“accurately represent” the H2S concentration combusted at the flares. First, Defendant claims
that Plaintiffs’ reliance on data from 2016 and 2017 to prove monitoring violations in 2012–
2015, is insufficient. It points to Plaintiffs’ own expert’s declaration that the composition of
gases combusted at the flares can vary over time as evidence that Plaintiffs’ evidence of
discrepancies in measurements over different years could not establish violations. Second,
Defendant argues that other operational considerations render the data relied on by Plaintiffs
unreliable. Namely, Defendant points to the 2015 and 2016 turnaround that involved extensive
42
Defendant incorrectly characterizes the accurate representation provision, § 60.105(a)(4)(ii), as an
exemption. This is not an exemption; it is an alternative method of complying with the regulation’s monitoring
requirement in subsection (a)(3) as explained above.
43
See United States v. First City Nat’l Bank of Houston, 386 U.S. 361, 366 (1967); Anderson v. Farmland
Indus., Inc., 70 F. Supp. 2d 1218, 1226 (D. Kan. 1999).
13
equipment upgrades, as well as other operational problems that rendered the new monitors’ data
unreliable.
Plaintiffs present strong circumstantial evidence that the fuel gas drum monitor did not
accurately represent the H2S concentration at the flares on the specific dates in question. Once
new monitors were installed at the flares in November 2015, they began recording concentration
levels far above the levels that were recorded at the fuel gas mix drum. According to Peterson’s
Declaration, the first data he received from Defendant was in June 2016, showing high levels of
H2S concentrations above the limit. Plaintiffs presented data in the SOP demonstrating that
Defendant’s data “showed multiple exceedances of the 162 ppm H2S concentration limits at the
flares after October 25, 2016.”44
Plaintiffs’ expert, Dr. Ranajit Sahu, discusses the specific data for the monitor at the fuel
gas mix drum and the new H2S monitor at the CWP flare. According to Dr. Sahu, between
October 25, 2016 and May 1, 2017, the monitor at the fuel gas mix drum reported H2S
concentrations between 10 and 30 ppm for the vast majority of the hours excluding calibration.
During the same period, the new H2S monitors at the CWP flare consistently reported H2S
concentrations up to 300 ppm. The H2S monitors at the flares were “pegged” at 300 ppm,
meaning they could not measure concentrations above 300 ppm. Dr. Sahu contends that, based
on the documents he reviewed, “the actual H2S concentration of gas measured by CWP flare
monitor was likely multiples higher than 300 ppm.”45 The Court finds credible and persuasive
Dr. Sahu’s independent expert opinion on this issue.
44
Doc. 54-3 at 27.
45
Doc. 80, Sahu Decl. ¶ 27.
14
Defendant asserts that the two turnarounds at the Refinery explain the discrepancy in data
relied on by Plaintiffs. The turnarounds occurred in the fall of 2015 and spring of 2016. The
data cited by Plaintiffs is from later in 2016 and early 2017, after these turnarounds. Other than
generic evidence that the refining process is “dynamic,” Defendant fails to explain how its two
turnarounds in 2015 and early 2016 impacted the data relied on by Plaintiffs to establish the
monitoring discrepancy between the CWP flare and the fuel gas mix drum later in 2016 and early
2017.
Defendant’s independent chemical engineering expert, David Wall, states that some of
the connections to the flares release gases to manage process upsets, causing “small amounts of
gas [to] continuously ‘leak’ to the flare during normal refinery operation.”46 And he contends
that the turnarounds identified seventeen leaking valves in the various process units in the
Refinery. But Defendant fails to explain how these leaks could explain the substantial data
discrepancies identified by Plaintiffs’ evidence. The difference in recorded H2S concentration
between the fuel gas mix drum monitors and the 2015 flare monitors are substantial—over 100
ppm different. The Court finds that Plaintiffs have presented circumstantial evidence that
demonstrates by a preponderance of the evidence that Defendant violated Subpart J on each day
between April 20, 2012 and November 11, 2015, because the monitor was not in a location that
“accurately represents the concentration of H2S in the fuel gas being burned” under 40 C.F.R.
§ 60.105(a)(4)(ii).
b.
Exemptions from Monitoring under § 60.105(a)(4)(iv)
As discussed above, subsection (a)(4)(iv) provides monitoring exemptions for gases
under § 60.104(a)(1)—“process upset gases or fuel gas that is released to the flare as a result of
46
Doc. 65, Wall Decl. ¶ 31.
15
relief valve leakage or other emergency malfunctions”—and gas streams combusted in a fuel gas
combustion device that are inherently low in sulfur content. Defendant contends that these
exemptions apply here.
Defendant urges the Court to consider the 906 connections between the fuel gas mix
drum and the flares and purports to account for all 906 connections and explain why any gas
released from these connections either would have been accurately represented by the monitor at
the fuel gas mix drum, or was exempt from monitoring. Defendant relies almost exclusively on
its independent expert Wall’s opinion to prove that exemptions apply. Wall’s opinion in turn is
entirely based on his analysis of the various connections listed on Defendant’s Documentation,
Minimization, and Analysis Tool (“DMAT”), a document it used to prepare the flare connections
list for the Coker and CWP flares as of November 2015. He discusses the various categories of
connections and opines whether they “would” be accurately represented by the fuel gas mix
drum monitor, or were exempt. According to Plaintiffs, this itemized account of the 906
connections between the monitors was not presented by Defendant during the parties’ informal
negotiations, despite Plaintiffs’ request that Defendant provide the basis for its claimed
exemptions. Nor were the DMAT tables that Wall relies on previously provided to Plaintiffs.47
According to Dr. Sahu, the DMAT tables differ from the Flare Management Plans (“FMPs”)
previously provided to Plaintiffs in terms of the amount of information about each connection.
As an initial matter, the Court is troubled by Defendant’s presentation of new evidence
on this highly complicated, technical, and dense issue that apparently was not presented to
Plaintiffs at the informal negotiation stage, at least not at this level of detail. Defendant admits in
the reply brief that while it “has asserted all along that any non-monitored streams relieving to
47
See Doc. 80, Sahu Decl. ¶¶ 28–29.
16
the Flares were exempt,” there is no “legal support” for the assertion that its newly specific
arguments are too late.48 While it may be true that Defendant previously claimed that
exemptions applied generally to the connections between the monitors’ locations during informal
negotiations, it does not contest that its inventory of 906 connections based on the DMAT
presented in its merits brief was not provided to Plaintiffs during informal negotiations.49
Indeed, Plaintiffs’ SOP makes clear that it asked Defendant to provide evidence to support its
assertion that exemptions applied; there is no indication that the DMAT was put forward in
response to those demands. Generally claiming that exemptions apply is a far cry from
providing expert testimony and new documentation about hundreds of connections that
Defendant asserts are explained away by exemptions.
Of course, the purpose of the informal negotiation provision in the 2012 CD is to
encourage the informal resolution of disputes before they reach the Court. Waiting to ask the
Court to consider in the first instance the status of 906 different connections in the Refinery,
based on dueling expert testimony, is not in keeping with the spirit of the informal negotiation
requirement in the 2012 CD, to which the parties agreed to be bound.50 And the Court finds it
odd that if this was Defendant’s explanation for the discrepancy in the monitors’ readings, it
would not provide this information to Plaintiffs during the lengthy process that led up to
petitioning this Court for review. To assert that there is no “legal support” for Plaintiffs to
48
Doc. 84 at 9–10 n.4.
49
See Doc. 54-3 at 24–28 (addressing Defendant’s response to Plaintiffs’ stipulated penalty demands,
which did not include the DMAT, including a reference to CRRM’s September 30, 2020 statement that it “has not
found a way to identify each discrete instance in which process gas was released to a flare or relief valve was
leaking to a flare for the period of time prior to November 2015.”).
50
Doc. 14 ¶ 219 (“Dispute resolution shall be commenced by a Defendant under the Consent Decree by
giving written notice to another Party advising of a dispute pursuant to this Section XIII. The notice shall describe
the nature of the dispute, and shall state the noticing Party’s position with regard to such dispute.”).
17
complain about this strategy because this Court’s scheduling order permitted it to file a
supplemental merits brief is disingenuous. Nothing in the Court’s Order permitting
supplemental merits briefing signaled that the parties could include matters that were not fairly
presented during the informal negotiation process. Indeed, had the Court understood the scope
of Defendant’s intended belated argumentation, it may have reached a different result on
Defendant’s request for supplemental briefing.
Despite Defendant’s eleventh hour attempt to bombard this Court with new evidence and
highly technical explanations about hundreds of instances of claimed exemptions that were not
fairly presented to Plaintiffs prior to petitioning this Court for judicial review, the Court will
address Defendant’s assertion that these exemptions apply.
The DMAT is the primary source Wall relied on in formulating his opinion that
Defendant either complied with or was exempt from Subpart J’s monitoring requirement.
According to Wall, the DMAT documented “[e]ach source and type of connection to the flare
header system[s].”51 The connections were “highlighted by a group of third-party reviewers and
documented in the DMAT, who then had discussions with operators and/or engineers from each
process unit to determine the frequency of contributions from each connection to the flares and
the anticipated volume of such contributions.”52 Defendant attempts to account for all 906
connections listed in the DMAT between the refinery process units and the three refinery flares,
85 of which connect to the Alky flare that is not at issue here.
As an initial matter, Plaintiffs’ expert calls into question the accuracy of the many
classification judgments contained in the DMAT. Dr. Sahu points out that the DMAT does not
51
Doc. 65, Wall Decl. ¶ 13.
52
Id.
18
make clear “the basis and methodology for classifications of high and low H2S concentrations.”53
The Court is persuaded by this evidence, particularly in light of Defendant’s inexplicable
decision to produce the DMAT for the first time after the dispute reached the Court.
The Court need not and will not engage in a connection-by-connection analysis to resolve
whether Defendant has met its burden to show it was exempt from Subpart J’s monitoring
requirement. The Court only needs to find that Defendant’s itemized assertions of exemption do
not fully account for the substantial discrepancy in H2S concentration measurements at the fuel
gas mix drum and the flares, as demonstrated by the data presented by Plaintiffs. Plaintiffs
address three categories of claimed exemptions and explain why Wall’s assertions of exemption
are insufficient: (1) gas streams that Defendant claims are exempt because they are “inherently
low in sulfur”; (2) two connections from the feed surge drums on the Vacuum No. 2 and No. 3
that Defendant claims are exempt as process upset gas, and (3) inadvertent leaks from the various
connections that Defendant claims qualify for an exemption as “relief valve leakage.” The Court
agrees with Plaintiffs that Defendant fails meet its burden of showing that the gas streams from
these connections are exempt from monitoring. Nor does Defendant’s evidence rebut Plaintiffs’
showing by a preponderance of the evidence that the monitor at the fuel gas mix drum did not
accurately represent the concentration of H2S in the fuel gas being burned at the flares.
i.
Gas Streams “Inherently Low in Sulfur”
First, Defendant contends that several gas streams are exempt because they are inherently
low in sulfur. CRRM contends that 22 connections between the CWP flare and the Dehexanizer
unit have a sulfur content so low that they would be accurately represented by the monitor at the
fuel gas mix drum. But, as Plaintiffs point out and Defendant concedes, Defendant did not apply
53
Doc. 80, Sahu Decl. ¶ 13.
19
for a monitoring exemption for these connections, as required by § 60.105(b), because they are
“not specifically exempted under § 60.105(a)(4)(iv).”54 Accordingly, Defendant fails to establish
by a preponderance of the evidence that these 22 connections are exempt under the regulation.
Defendant asserts that these connections are also exempt as process fuel gas because they
are used to relieve gas to the flares during a process upset. Plaintiffs respond that these
connections do not automatically qualify for an exemption as process fuel gas based on their
designation as “maintenance” connections. Dr. Sahu explains that “[m]aintenance can occur at
any time and can be conducted outside of start-up and shut-down time periods,” and thus, these
connections “relieve to the CWP Flare during start-up, shut-down, malfunction, or upset events,
but can also relieve during other periods of routine operation, such as ‘hot work’ maintenance.”55
Therefore, Defendant fails to show that these connections are exempt as process fuel gas.
Similarly, Defendant fails to meet its burden of demonstrating that all 88 gas streams
designated as “intermittent” or “continuous” are exempt from monitoring. Defendant asserts that
the H2S concentration in these streams is accurately represented by the monitor at the fuel gas
mix drum because they would not have a measurable impact on the H2S concentration measured
at the flares. These connections include control valves, manual bypass valves, manual vents,
pump seals, sample vents, and sweep vents. As Dr. Sahu explains:
Various process units are connected to the flares through these
intermittent and continuous streams. The waste gas composition to
each of these flares is different, and that composition varies over
time. The single H2S monitor, located downstream of the single
fuel gas mix drum, cannot logically represent the H2S
concentration in the continuous and intermittent connections going
to each of the two flares.56
54
See Doc. 64 n.2.
55
Doc. 80, Sahu Decl. ¶ 31.
56
Id. at ¶ 22.
20
The Court agrees with Plaintiffs that Subpart J’s exemption provision does not allow Defendant
to unilaterally decide not to monitor certain gas streams based on its belief that they would have
a de minimus impact on H2S concentrations. And the Court is persuaded by Dr. Sahu’s
declaration. As the Court previously determined, Plaintiffs’ data shows by a preponderance of
the evidence that the fuel gas drum monitor did not accurately represent the H2S concentration at
the flares. These 88 gas streams that are designated by Defendant as “intermittent” or
“continuous” are not exempt from monitoring based on Defendant’s unilateral determination that
they would not have a measurable impact on the H2S concentration measured at the flares.
ii.
Connections from the Feed Surge Drums on Vacuum
No. 2 and No. 3
Second, the parties discuss two connections from the feed surge drums on the Vacuum
Unit No. 2 and No. 3, which impact the Coker flare only. According to Wall, these connections
“open to the flare header when needed to maintain a safe and stable pressure of blanket gas in the
vessel.”57 Wall estimates that “the additional contribution from the Vacuum Unit No. 2 and
Vacuum Unit No. 3 feed surge drum vents could theoretically raise the total [Coker] flare gas
H2S concentration to approximately 86.7 ppmv, which is well below the 162 ppmv H2S
concentration limit.”58 Wall opines:
[W]ith the exception of the Vacuum Unit No. 2 and Vacuum Unit
No. 3 feed surge drum valves, gases combusted in the Coker flare
from connections that were not monitored by the H2S analyzer at
the fuel gas mix drum were either accurately represented by the
H2S analyzer on the mix drum or only would have released gases
to the flares that were generated from process units as a result of
start-up, shutdown, upset, or malfunction or relief valve leakage.
Based on historical data and engineering estimates, the gases from
the Vacuum Unit No. 2 and Vacuum Unit No. 3 feed surge drum
57
Doc. 65, Wall Decl. ¶ 29.f.iv.
58
Id.
21
valves would not have resulted in exceedances of the 162 ppmv
H2S concentration standard for the Coker flare.59
Wall’s declaration demonstrates that these two connections released gas streams that
were not in compliance with Subpart J’s monitoring requirement for the Coker flare. Defendant
conflates two separate Subpart J requirements—monitoring and concentration limits. The fact
that gas streams from these connections did not exceed the H2S regulatory limit does not mean
that the fuel gas mix drum monitor accurately represented the measurement at the flares. Indeed,
according to Wall, the H2S concentration from these connections could have been raised to 87
ppmv, well in excess of the average measurement at the fuel gas mix drum. That this amount did
not exceed the concentration limit in Subpart J is irrelevant to the monitoring question, which
asks if the single monitor used by CRRM between 2012 and 2015 “accurately represents the
concentration of H2S in the fuel gas being burned” at the flares. Defendant’s position that “since
these gases would not result in an exceedance of the 162 ppm H2S concentration standard, they
were not required to be separately monitored, since the entire purpose of NSPS Subpart J’s
monitoring requirements is to ensure compliance with that standard,” is unavailing because it is
untethered to the plain language of the regulation.60 Thus, the evidence presented by Defendant
about these two connections alone establishes that a connection-by-connection analysis fails to
account for the disparate measurements between the old monitor and the new monitor at the
Coker flare.
iii.
Relief Valve Leakage
Finally, Defendant contends that differences in H2S concentrations recorded from the
monitor at the fuel gas mix drum and the flare headers could be explained by the gases leaking
59
Id. ¶ 36.
60
Doc. 84 at 13.
22
from relief valves in various process units throughout the Refinery. Defendant claims such leaks
are exempt as fuel gas that is released to the flares “as a result of relief valve leakage or other
emergency malfunctions.”61 Plaintiffs argue that this exemption does not apply to relief valve
leakage from non-emergency events.
This exemption applies to “fuel gas streams that are exempt under § 60.104(a)(1).”62
Section 60.104(a)(1) in turn exempts “[t]he combustion in a flare of process upset gases or fuel
gas that is released to the flare as a result of relief valve leakage or other emergency
malfunctions.”63 The parties dispute whether “relief valve leakage” must occur as an emergency
malfunction in order to be exempt. Defendant urges the Court to consider the definitions of
“leak” and “leakage” and conclude that relief valve leakage contemplates “accidental or
inadvertent release of gas or fluid under any number of circumstance (i.e., emergency or
otherwise).”64 The term “leak” is defined as “to enter or escape through an opening usually by a
fault or mistake”65 and “leakage” means “the act or process or an instance of leaking.”66 Based
on these definitions, Defendant argues that the plain meaning of “relief valve leakage” is not
limited to emergency situations.
Plaintiffs respond that “relief valve leakage” must be read in conjunction with “or other
emergency malfunctions,” and when done so, it unambiguously applies to emergency situations
only. Under the principle of noscitur a sociis, “a word is known by the company it keeps—to
61
40 C.F.R. §§ 60.105(a)(4)(iv), 60.104(a)(1).
62
Id. § 60.105(a)(4)(iv).
63
Id. § 60.104(a)(1).
64
Doc. 84 at 15.
65
Leak, Merriam-Webster.com, https://www.merriam-webster.com/dictionary/leak (last visited March 8,
2022).
66
Leakage, Merriam-Webster.com, https://www.merriam-webster.com/dictionary/leakage (last visited
March 8, 2022).
23
“avoid ascribing to one word a meaning so broad that it is inconsistent with its accompanying
words, thus giving unintended breadth to the Acts of Congress.”67 Thus, Plaintiffs argue, relief
valve leakage under the regulation occurs only when there is an emergency malfunction; it does
not apply to “steady” relief valve leakage outside of an emergency situation. This reading of the
exemption is consistent with EPA’s interpretive guidance.68
The Court finds that the regulation is unambiguous. The Court begins with the dictionary
definitions of the words in question because the regulation does not define “relief valve
leakage.”69 Defendant is correct that the ordinary meaning of “leak” does not require an
emergency. But the Court agrees with Plaintiffs that as part of its plain language reading of the
regulation, it must give effect to each word and clause, not just the meaning of a single word.70
In order to give effect to the words “or other emergency malfunctions,” relief valve leakage must
occur as part of an emergency malfunction, not as steady streams of relief valve leakage that
occur outside of an emergency, as urged by Defendant. Defendant’s interpretation of this
language would render the words “or other” meaningless, instead allowing an exemption for
relief valve leakage and emergency malfunctions. Under the principle of noscitur a sociis and
the requirement that this Court give meaning to each word in the regulation, Plaintiffs’
interpretation is the only one in keeping with the plain language of the regulation.
Defendant suggests that the word “other” does not modify “relief valve leakage,” but
instead distinguishes the phrase “emergency malfunction” from the word “malfunction” in the
67
Yates v. United States, 574 U.S. 528, 543 (2015).
68
See Applicability Determination from David Howekamp, U.S. EPA, to Armand S. Abay, Texaco
Refining & Marketing, Inc. (May 14, 1998) (interpreting the exemption as applying only to emergency situations).
69
Canyon Fuel Co. v. Sec’y of Lab., 894 F.3d 1279, 1288 (10th Cir. 2018) (citation omitted).
70
See id. at 1289 (citing Bridger Coal Co./Pac. Minerals, Inc. v. Dir., Office of Workers’ Comp. Programs,
U.S. Dep’t of Labor, 927 F.2d 1150, 1153 (10th Cir. 1991)).
24
process upset gas definition. The Court disagrees. First, Defendant solely relies on regulatory
history to support its interpretation and to argue that EPA only within the last ten years began to
interpret the regulation as applying to fuel gas leakage in emergency situations. But as the Court
has already stated, it is not to “consider regulatory history or anything outside the text” when
examining the plain meaning of the language in the regulation.71
Second, Defendant’s interpretation is not supported by a plain reading of the regulatory
language. The exemption applies to: “[t]he combustion in a flare of process upset gases or fuel
gas that is released to the flare as a result of relief valve leakage or other emergency
malfunctions.”72 Thus, the exemption applies to “the combustion in a flare of [1] process upset
gases or [2] fuel gas that is released to the flare as a result of relief valve leakage or other
emergency malfunctions.” The clause beginning with “that” is used here to define fuel gas, not
process upset gases, and the term “or other emergency malfunctions” is a part of that defining
clause.
Moreover, the term “emergency malfunction” does not relate back to “process upset
gases,” which is separately defined from “fuel gas.” “Process upset gas” is defined as “any gas
generated by a petroleum refinery process unit as a result of start-up, shut-down, upset or
malfunction.”73 The exemption applies to process upset gas as so defined, “or fuel gas that is
released to the flare either as a result of relief valve leakage or other emergency malfunctions.”
“Fuel gas means any gas which is generated at a petroleum refinery and which is combusted.”74
The plain language of this phrase is that “other emergency malfunctions” references “relief valve
71
Id. at 1287.
72
40 C.F.R. § 60.104(a)(1).
73
Id. § 60.101(e).
74
Id. § 60.101(d).
25
leakage,” not process upset gases. Accordingly, a plain language reading of this unambiguous
regulation supports Plaintiffs’ interpretation. Defendant does not contest that the relief valve
leakage it seeks to exempt did not occur as part of an emergency malfunction. Thus, to the
extent unmonitored streams were due to steady relief valve leakage, they are not exempt from
Subpart J.
In conclusion, the Court finds that Plaintiffs have met their burden of demonstrating a
factual basis for the stipulated penalty demands in Claims 1 and 2 based on violations of Subpart
J between April 10, 2012 and November 11, 2015.
2.
Plaintiffs’ Delay in Challenging the CEMS Placement
Defendant argues that Plaintiffs’ delay in challenging the placement of Defendant’s H2S
monitor bars them from now seeking stipulated penalties for the period in question. Defendant
provides several iterations of this argument—that Plaintiffs’ claims constitute a “post hoc
reinterpretation” of the regulation’s monitoring requirements that the Court should reject because
it constitutes unfair surprise, that the claims are time-barred under the doctrine of laches, and that
the stipulated penalties should at least be reduced under the Court’s equitable authority. The
Court is not persuaded by any of these arguments.
First, there is no evidence that Plaintiffs had knowledge of the violations at the time they
entered into the consent decrees. Defendant fails to controvert Plaintiffs’ evidence that it relied
on CRRM’s assurances before 2016 that only exempt streams were allowed to release to the
Coker and CWP flares. It was not until the monitoring data was provided beginning in 2016 that
Plaintiffs learned of the discrepancy in H2S concentration measurements. The absence of
injunctive relief related to the fuel mix drum monitor in the 2012 CD does not mean that
Plaintiffs made an affirmative determination that the monitor was compliant with Subpart J.
26
According to Plaintiffs’ evidence, they did not have the data to make that determination before
the 2012 CD. Plaintiffs did not affirm that Defendant’s monitor near the fuel gas mix drum was
in compliance with Subpart J when it entered into the 2004 and 2012 Consent Decrees.75
Second, there is no evidence that the KDHE had knowledge of the violation when it
issued construction and operating permits to Defendant in 2006 that required both flares to
comply with Subpart J’s monitoring requirements. Defendant contends that because the monitor
was located at the fuel gas mix drum at the time, KDHE would have imposed a compliance plan
and schedule in the permits if Defendant was out of compliance. But again, KDHE’s decision to
issue these permits did not “affirm” or make a “determination” about the monitor’s compliance
with Subpart J. There is no affirmative finding in those permits that the H2S monitor was in
compliance with Subpart J. Indeed, the short permitting process and broad enforcement
authority given to the EPA does not allow for an exhaustive procedure for regulators to
investigate and resolve all areas of noncompliance.76
Defendant’s argument that Plaintiff’s interpretation of the regulation in the SOP
constitutes unfair surprise is also misplaced. The cases cited by Defendant discuss this issue in
the context of Auer deference—once a court decides that a regulation is ambiguous and that the
agency’s interpretation is reasonable, unfair surprise is one reason why a court may still decide
not to defer to an agency’s interpretation of a regulation.77 But Defendant never argues that the
regulation at issue here is ambiguous. Defendant argues that Plaintiffs misinterpreted the
regulation and attempted to impose Subpart Ja prematurely to the Refinery’s fuel gas mix drum
monitor. But the Court has determined that Plaintiffs did not misread the regulation in finding
75
See Doc. 8 ¶¶ 130, 138, 139; Doc. 14 ¶¶ 66.b, 231, 237.
76
See Citizens Against Ruining the Env’t v. E.P.A., 535 F.3d 670, 678 (7th Cir. 2008).
77
Kisor v. Wilkie, 139 S. Ct. 2400, 2417–18 (2019).
27
that CRRM was in violation between 2012 and 2015. And Plaintiffs’ stipulated penalty demand
cannot be considered unfair surprise given the lack of evidence it knew about the placement of
CRRM’s monitor before 2016.
Additionally, the defense of laches is not available to Defendant here. “Since at least
1940, ‘the general rule [has been] that the United States is not “subject to the defense of laches in
enforcing its rights.”’”78 Although there are some limited exceptions in specific cases, “the
Tenth Circuit has generally declined to expand on those exceptions.”79 Defendant acknowledges
this law, but asks the Court to apply an exception here because it is an egregious instance of
laches.80 The Court disagrees. As already discussed, the evidence demonstrates that Plaintiffs
first learned of the monitoring violation in 2016, informed Defendant of the potential
enforcement action in 2018, and then the parties entered into tolling agreements. This was not an
egregious delay.
Finally, the Court declines to exercise its equitable authority to reduce the stipulated
penalty demand under these circumstances. As discussed, there is no evidence that Plaintiffs
discovered the violation prior to 2016, nor that they had a duty to investigate prior to that time to
determine whether there was a violation. The 2012 CD provides for stipulated penalties for
Defendant’s failure to comply with Subpart J, and Plaintiffs have shown by a preponderance of
the evidence that Defendant violated Subpart J on the dates alleged, triggering the stipulated
penalties in paragraph 189. Under such circumstances, the Court does not have discretion to
78
FTC v. Superior Prods. Int’l II, Inc., No. 2:20-cv-02366-HLT-GEB, 2020 WL 7480390, at *2 (D. Kan.
Dec. 18, 2020) (quoting FDIC v. Hulsey, 22 F.3d 1472, 1490 (10th Cir. 1994)) (citations omitted).
79
Id. (citing Hulsey, 22 F.3d at 1490).
80
See United States v. Admin. Enters., Inc., 46 F.3d 670, 673 (7th Cir. 1995).
28
reduce the stipulated penalties that should be imposed.81 Therefore, Defendant’s request for an
equitable reduction to the stipulated penalty demand is denied.
In sum, the Court finds no undue delay in this case that would justify barring or reducing
Plaintiffs’ stipulated penalty demands on Claims 1 and 2.
IV.
Violations of Subpart Ja: SOP Claims 3–16
Paragraph 61(a) of the 2012 CD provides:
If, prior to the termination of this Consent Decree, a Flaring
Device becomes subject to NSPS Subpart Ja for a regulated
pollutant due to a “modification” (as that term is defined in the
final Subpart Ja rule), the modified affected facility shall be subject
to and comply with Subpart Ja, in lieu of NSPS Subpart J, for that
regulated pollutant to which a standard applies as a result of the
modification.82
It is undisputed that the CWP and Coker flares were modified and became subject to NSPS
Subpart Ja on November 11, 2015. Claims 3–16 in the SOP assert violations of paragraph 61 of
the 2012 CD at the Coker and CWP flares on various days between November 11, 2015 and June
30, 2017.
Defendant challenges these stipulated penalty demands on several grounds. Defendant
first challenges Plaintiffs’ stipulated penalty demands as not supported by the terms of the 2012
CD because: (1) the 2012 CD prohibits Plaintiffs from demanding both stipulated penalties under
the consent decree and civil penalties in a separate complaint for Subpart Ja violations; and (2)
Plaintiffs’ calculation of stipulated penalties does not comply with ¶ 189. Defendant also raises
several factual challenges: (1) to Claims 3–4 on the basis that it complied with its obligation to
operate and maintain flow monitors at the flares; (2) to Claims 5–6, 13–14, and 15–16 on the
81
See United States v. Volvo Powertrain Corp., 854 F. Supp. 2d 60, 71–72 (D.D.C. 2012) (fashioning
equitable remedy where stipulated penalty provision did not apply to a consent decree violation).
82
Doc. 14 ¶ 61(a).
29
basis that it timely complied with requirements for performance tests and evaluations; and (3) to
Claims 11–12 on the basis that it complied with the span value requirements for the flares’ TRS
analyzers. The Court addresses Defendant’s points of error in turn.
A.
Claim Splitting
First, Defendant argues that Plaintiffs’ stipulated penalty demands are barred because
Plaintiffs are simultaneously seeking civil penalties for violations of Subpart Ja in the first two
counts of their FASC. Plaintiffs maintain that these parallel remedies are permitted by the 2012
CD because they sought stipulated penalties before filing a new complaint, and because they
seek to recover for different Subpart Ja violations in the FASC.83
The first two counts in the FASC are for exceedances of the H2S concentration limit at
the Coker and CWP flares, in violation of Subpart Ja. The first count for relief applies to the
Coker flare and alleges that Defendant exceeded the H2S concentration limit on at least 318 days
since November 10, 2015, when Defendant became subject to Subpart Ja. In the alternative,
Plaintiffs allege that the flare’s monitoring data was inaccurate, so Defendant failed to
“adequately operate, calibrate, and/or maintain the H2S CEMS on the Coker Flare on such days,”
as required by Subpart Ja.84 The second count applies to the CWP flare and alleges exceedances
on at least 486 days, or alternatively, that Defendant failed to adequately monitor or maintain the
CEMS monitor on that flare, all in violation of Subpart Ja. On both counts, Plaintiffs seek
“injunctive relief and the assessment of civil penalties to the United States of not more than the
83
After the briefing was complete on the petition, Plaintiffs filed the FASC. Doc. 90. Defendant filed a
partial motion to dismiss the FASC on March 21, 2022. Doc. 91. The Court considers Defendant’s claim splitting
arguments as applied to the FASC since the first two counts are the same.
84
Doc. 90 ¶ 140.
30
per-day per-violation amounts set forth in Paragraph 82 above,” as well as injunctive relief and
civil penalties to the State of Kansas.85
The issue of parallel remedies is explicitly addressed in paragraph 205 of the 2012 CD:
205. Subject to the provisions of Section XIV of this Consent
Decree (Effect of Settlement/Reservation of Rights), the stipulated
penalties provided for in this Consent Decree shall be in addition
to any other rights, remedies, or sanctions available to the United
States or State for CRRM’s violation of this Consent Decree or
applicable law. Where a violation of this Consent Decree is also a
violation of the Clean Air Act, CRRM shall be allowed a credit, for
any stipulated penalties paid, against any statutory penalties
imposed for such violation. The United States and State will not
demand stipulated penalties for a Consent Decree violation if they
have commenced litigation seeking penalties under the Clean Air
Act for such violation. Notwithstanding the foregoing, the United
States reserves all its rights to pursue, under the Consent Decree
and/or outside of it, any other non-monetary remedies to which it is
legally entitled, including but not limited to injunctive relief for
violations of the Consent Decree.86
The parties have different interpretations of this provision, but the Court agrees with
Plaintiffs that paragraph 205’s plain meaning is unambiguous and controls. Defendant
repeatedly argues that paragraph 205 prohibits Plaintiffs from “simultaneously” demanding
stipulated penalties under the 2012 CD and pursuing litigation for penalties under the CAA for
the same violations. That is not what paragraph 205 says. As Plaintiffs correctly argue, they
sought stipulated penalties before, not after, commencing litigation seeking penalties for Subpart
Ja violations, which is explicitly permitted under paragraph 205. Plaintiffs filed their stipulated
penalty demand on June 19, 2020; the Supplemental Complaint was filed on December 28, 2020.
Moreover, paragraph 205 contemplates exactly this situation because it provides that: (1)
the stipulated penalties under the CD are “in addition to any other . . . remedies . . . available to
85
Id. ¶¶ 143–44.
86
Doc. 14 ¶ 205.
31
[Plaintiffs] for CRRM’s violation of this Consent Decree or applicable law”; and (2) where a
violation of the CD is also a violation of the CAA, Defendant must be allowed a credit based on
those stipulated penalties against any statutory penalties imposed under the FASC. Plaintiffs
seek additional remedies available to them under the CAA in the FASC. To the extent
Defendant becomes liable on those claims, they will be allowed a credit based on the stipulated
penalties already imposed for violating the 2012 CD on the same dates.
B.
Calculation of Stipulated Penalties Under Paragraph 189
Defendant challenges how Plaintiffs calculated their stipulated penalty demand under
paragraph 189 of the 2012 CD, which governs the calculation of stipulated penalties for failure to
comply with NSPS Subpart Ja.
189. Section V.J.: NSPS for Flaring Devices. For failure to
comply with applicable NSPS Subparts A and J (or Ja if CRRM
becomes subject to Ja during the term of this Consent Decree)
requirements for flaring devices, including emission limits, per
Flaring Device:
Period of Non-Compliance
1st through 30th day
31st through 60th day
Beyond the 60th day
Penalty per day
$500
$1,500
$2,000 or an amount equal
to 1.2 times the economic
benefit of delayed
compliance,
whichever is greater.
Specifically, Defendant objects that: (1) Plaintiffs’ “subsumation” approach—demanding a
suspended stipulated penalty for concurrent Subpart Ja violations on a particular day at a
particular flare—violates paragraph 189; (2) Plaintiffs incorrectly imposed graduated penalties;
(3) Plaintiffs incorrectly demanded separate stipulated penalties for the Coker and CWP flares;
and (4) Plaintiffs incorrectly demanded penalties on multiple days for discrete Subpart Ja
violations.
32
1.
Subsumed Violations
When they calculated stipulated penalties for Subpart Ja violations, Plaintiffs assessed
one stipulated penalty per flare, per day, even though they alleged that Defendant often violated
multiple Subpart Ja provisions at the same flare on the same day. Plaintiffs refer to this as
“subsumation” because one flaring violation on a particular day (the primary violation) subsumes
the stipulated penalties for any additional flaring violation that occurred at the same flare on the
same day. Plaintiffs’ initial Demand explained:
At times CRRM violated five or more NSPS Ja flaring
requirements on a single day. However, Plaintiffs seek only one
stipulated penalty per day per flare for these violations. Therefore,
for all of CRRM’s Subpart Ja flaring violations with corresponding
stipulated penalties that are subsumed in whole or part by other
violations under this calculation, Plaintiffs reserve the right to seek
stipulated penalties for those previously subsumed violations if any
such violations are later withdrawn, or somehow found not to be
violations.87
Plaintiffs referred to an Excel spreadsheet that they sent Defendant that identified all violations
by type and date, including those they deemed subsumed.
In the Demand, Plaintiffs stated an amount due for fully subsumed violations as “$0,*”
and placed an asterisk next to certain other amounts, indicating that these amounts were
“subsumed by other concurrent Subpart Ja violations.”88 On several violations, Plaintiffs stated
that under paragraph 189 of the 2012 CD, “all of the stipulated penalties” for that violation “are
subsumed by other concurrent Subpart Ja violations, as detailed in the previously emailed Excel
spreadsheet.”89
87
Doc. 54-1 at 3.
88
Id. at 4–5 (Claims 3–4, 5–6, 7–8, 13–14).
89
Id. at 5–6 (Claims 9–10, 11–12, 15–16).
33
Later, in a Supplemental Demand, Plaintiffs clarified that they were in fact demanding
stipulated penalties for all violations that were labeled subsumed; however,
because the Consent Decree limits arguably stipulated penalties to
one stipulated penalty per flare, per day, for penalties that were
described as “subsumed” in the demand letter, Plaintiffs are
demanding such penalties but suspending CRRM’s obligation to
pay such penalties at this time (and the escrowing of such funds if
the claims are disputed) until Plaintiffs determine the amount of
offset due to subsumation.90
This Supplemental Demand calculated the full amount of suspended stipulated penalties for the
subsumed violations.
Defendant challenges this approach, arguing that it deprived it of the 2012 CD’s dispute
resolution provisions by allowing Plaintiffs to “suspend” penalties that exceed the maximum
penalty per day provided under paragraph 189 and then “bring those secondary violations back to
life if they fail to prove their ‘primary violation.’”91 By doing this, Defendant complains that it
did not have the ability to choose to pay the stipulated penalty for those secondary violations
rather than challenge them through the judicial review process.
The Court finds that Plaintiffs’ approach, while not explicitly provided for in the 2012
CD, does not violate its plain and unambiguous terms. First, the parties agree that paragraph 189
sets the maximum stipulated penalty per day, per flare for violations of Subpart Ja. There is no
dispute that Plaintiffs’ stipulated penalty demand cannot exceed these amounts. However,
nothing in the 2012 CD prevents Plaintiffs from finding multiple violations on the same day at
the same flare. Plaintiffs’ Demand and Supplemental Demand, along with the Excel spreadsheet
detailing the stipulated penalties and whether or not they are subsumed, provided clear notice to
90
Doc. 54-2 at 3.
91
Doc. 56 at 15.
34
Defendant about which provisions Plaintiffs claimed were violated on which days, and the total
stipulated penalty that corresponded to the violation. This is in keeping with paragraph 202’s
requirement that Plaintiffs’ demand include “the stipulated penalty amount the Plaintiffs have
demanded for each violation (as can be best estimated), the calculation method underlying the
demand, and the grounds upon which the demand is based.”92 Paragraph 202 does not require a
specific calculation method beyond what is provided for in paragraph 189; it only requires that
Plaintiffs’ demand include the calculation method they used and the violations associated with its
demand. Plaintiffs’ Demand, Supplemental Demand, and accompanying Excel spreadsheet
complied with these requirements.
Second, Plaintiffs’ approach complies with the plain terms of paragraph 189 when read in
conjunction with paragraph 180, the introductory paragraph to the Stipulated Penalties section of
the 2012 CD. That paragraph states that “CRRM shall pay stipulated penalties to the United
States and State for each failure to comply with the terms of this Consent Decree provided
herein.”93 The subsequent paragraphs in that section set forth the way stipulated penalties shall
be calculated, with paragraph 189 setting forth the calculation for Subpart Ja. The fact that
paragraph 189 sets forth a maximum stipulated penalty per day simply operates as a cap to the
daily stipulated penalty that can be collected.
Third, Defendant has had a full and fair opportunity to seek judicial review of both
“primary” and “secondary” violations that underlie the stipulated penalties demanded by
Plaintiffs. Paragraph 202 contemplates that there may be more than one violation to which a
stipulated penalty relates, as it provides that the “demand for the payment of stipulated penalties
92
Doc. 14 ¶ 202.
93
Id. ¶ 180 (emphasis added).
35
will identify the particular violation(s) to which the stipulated penalty relates.” Plaintiffs set
forth all applicable violations, some of which were concurrent, but only demanded that the
maximum penalty be paid in escrow while the parties litigated their dispute pursuant to
paragraph 203. Plaintiffs opted not to waive the concurrent violations, but instead, essentially
hold the duplicative penalties in abeyance pending a determination about whether the primary
violations are either withdrawn, or determined by the Court not to constitute violations.
Plaintiffs’ approach, although not explicitly provided for under the consent decree, allowed
Defendant to seek review of all alleged violations at once, even though the actual penalties
demanded are tied to dates of non-compliance with Subpart Ja, not the dates of each independent
Subpart Ja violation.
To the extent paragraphs 189 and/or 202 are ambiguous because they do not explicitly
provide for a method of demanding stipulated penalties when there are concurrent violations, the
Court must determine the intent of the parties “by considering all language employed, the
circumstances existing when the agreement was made, the object sought to be attained, and other
circumstances, if any, which tend to clarify the real intention of the parties.”94 The Court has
already found that the 2012 CD explicitly contemplated that there may be concurrent violations
that justify a stipulated penalty demand. And the stated purpose of the 2012 CD is to “further the
objectives of the Clean Air Act.”95 The 2012 CD also makes clear that “[t]he United States, after
consultation with the State, may, in its unreviewable discretion, waive payment of any portion of
stipulated penalties that may accrue under this Consent Decree.”96
94
Amoco Prod. Co. v. Wilson, Inc., 976 P.2d 941, 945 (Kan. 1999) (quoting Universal Motor Fuel, Inc. v.
Johnston, 917 P.3d 877, 881 (Kan. 1996)).
95
Doc. 14 ¶ 13.
96
Id. ¶ 202.
36
The Court cannot find that the parties intended to provide Plaintiffs with no recourse to
demand stipulated penalties for concurrent violations in the event that the primary basis for the
demand is withdrawn or dismissed on judicial review. Defendant suggests that Plaintiffs’
recourse was to issue a demand with multiple claims, but only “demand” stipulated penalties per
flare, per day, so that the parties and the Court could litigate disputes over only those claims for
which Plaintiffs can actually demand stipulated penalties. But this would render the waiver
provision meaningless—it would require Plaintiffs to waive payment of stipulated penalties that
may accrue under the consent decree and remove their discretion from that determination. And it
would require Plaintiffs to demand stipulated penalties one claim at a time per flare, which in
this case could have potentially resulted in eight separate consecutive demands that could trigger
judicial review. The Court cannot find that this procedure is in keeping with the parties’ intent as
expressed in the consent decree when read as a whole. Plaintiffs’ approach is a reasonable
method for demanding stipulated penalties for concurrent violations under the terms of the
agreement.
Finally, it is unclear what relief Defendant seeks with this challenge. As discussed
throughout this opinion, Defendant’s merits-based challenges—which they were given a full and
fair opportunity to present for judicial review—are unavailing. Thus, the stipulated penalty
demand for the “primary” violations have now been upheld and Defendant was provided an
opportunity to challenge all grounds for which Plaintiffs could potentially demand stipulated
penalties. Defendant is not and was not assessed an amount greater than what paragraph 189
allows. Even assuming Plaintiffs should have used a different method other than subsumation to
37
demand stipulated penalties for concurrent violations, it would not lead to this Court’s finding
that the amount actually demanded by Plaintiffs violates paragraph 189.97
2.
Graduated Penalties for Violations on Non-Consecutive Days
Defendant next challenges Plaintiffs’ calculation of stipulated penalties under paragraph
189 because they assessed graduated penalties of $1,500 or $2,000 regardless of whether the
specific violation continued consecutively for more than 30 or 60 days, respectively. But, as
Plaintiffs point out, this argument depends on an incorrect reading of paragraph 189 as applying
to a period of noncompliance for each type of Subpart Ja violation, rather than a period of
noncompliance for any Subpart Ja violation. Plaintiffs calculated the total number of days of
noncompliance with all Subpart Ja requirements and based its graduated penalties on this
assessment, rather than a violation-by-violation assessment of noncompliance. For example,
Claim 4 alleges a violation of Subpart Ja’s requirement to operate and maintain flow monitors at
the Coker flare. If Plaintiffs determined that Defendant violated this provision for 40 days and
ceased, but violated another Subpart Ja requirement on Days 41–45, they assessed penalties at
the graduated $1,500 per day amount rather than start over at $500 for the Day 41 violation.
The Court agrees that this approach is supported by the plain language of paragraph 189,
which sets forth tiers of stipulated penalties based on the “Period of Non-Compliance” and “[f]or
failure to comply with [Subpart Ja] requirements for faring devices.” Nothing in this paragraph
tethers the period of noncompliance to specific Subpart Ja violations. If the parties intended that
97
To the extent Defendant specifically challenges Claims 7–10 on the basis of subsumation, its challenge is
denied for the reasons stated in this section.
38
the penalties be tied to each separate Subpart Ja violation, they could have specified that in the
consent decree, but they did not.98
3.
“Per Flaring Device”
Defendant argues that because the Coker and CWP flares are a “single affected facility”
under NSPS Subpart Ja, Plaintiffs may only recover one stipulated penalty for any violation that
occurred at both flares on the same day. As Plaintiffs correctly note, Defendant yet again
avoided the informal resolution procedures in the 2012 CD by failing to raise this argument
during that process. Defendant also failed to identify this issue in its original petition for judicial
review—neither the Court nor the parties were placed on notice of this “threshold” issue that
does not touch on the substantive merits of the alleged violations.99 Nonetheless, the Court
addresses this argument, as the plain language of the 2012 CD easily disposes of this claim.
Paragraph 189 of the 2012 CD states that stipulated penalties “for flaring devices” are
calculated “per Flaring Device.” The 2012 CD defines “Flaring Device” as “an Acid Gas Flaring
Device and/or an HC Flaring Device.”100 The Coker flare is an Acid Gas Flaring Device.101 The
CWP flare is an HC Flaring Device.102 Thus, under the plain terms of the 2012 CD, they are
separate flaring devices. The Court is not persuaded by Defendant’s argument that the term
“flaring devices” in ¶ 189 is undefined. It is the plural of a defined term in the 2012 CD, agreed
to by all parties, and it is used elsewhere as the same term of art defined by the consent decree.
As paragraph 60 explains:
98
To the extent Defendant specifically challenges Claims 7–10 on the basis of its challenge to Plaintiffs’
imposition of graduated penalties, it is denied for the reasons stated in this section.
99
Doc. 14 ¶ 219.
100
Id. ¶ 14.p.
101
Id. ¶ 14.c.
102
Id. ¶ 14.x.
39
CRRM currently operates the following Flaring Devices at the
Refinery: (1) the Cold Pond Flare; (2) the Coker Flare; and (3) the
Alky Flare. The Cold Pond Flare and the Coker Flare are “affected
facilities” subject to the requirements of the NSPS, 40 C.F.R. Part
60, Subparts A and J for Fuel Gas Combustion Devices, and
CRRM shall comply with those provisions. Within two (2) years of
the Entry Date, the Alky Flare shall be an affected facility subject
to, and CRRM shall comply with the requirements of 40 C.F.R.
Part 60, Subparts A and J for Fuel Gas Combustion Devices.
The phrase “per Flaring Device” would be rendered meaningless if the Court adopted
Defendant’s new contention that the stipulated penalties provision should apply to the Coker and
CWP flares as one. Defendant’s argument that the possibility of violations at the Alky flare
breathes meaning into its flawed interpretation is unavailing. All three flares are separate flaring
devices for purposes of calculating penalties under ¶ 189 of the consent decree.
4.
Continuing Violations, Claims 5–6 and 13–16
Claims 5–6 and 13–16 each allege untimely compliance with certain Subpart Ja
requirements for H2S performance tests and evaluations at the flares. Plaintiffs assessed
stipulated penalties for each day that each of these requirements was late until the test or
evaluation was performed. Defendant challenges this approach, arguing that these claims are for
discrete, one-time violations, so Plaintiffs may only recover for a single day of stipulated
penalties for each claim—the day its performance was late. Plaintiffs respond that the plain
language of the 2012 CD provides for daily stipulated penalties until performance is complete,
that courts have found continuing violations where a requirement is an ongoing obligation, and
that the regulations provide that violations continue until the requirement is met.
The plain language of the 2012 CD resolves this dispute. Under paragraph 202,
stipulated penalties “begin to accrue on the day after performance is due or on the [d]ay a
violation occurs, whichever is applicable, and shall continue to accrue until performance is
40
satisfactorily completed or until the violation ceases.”103 Similarly, paragraph 189 states that
stipulated penalties for violations of Subpart Ja occur “per day.” The language in these two
paragraphs is consistent with other provisions of the 2012 CD, which include graduated penalties
for reporting violations where the report is due on a specific day.104 Here, Defendant was
required to conduct certain tests and evaluations by a specific day. Plaintiffs demanded
stipulated penalties on the day after the test was due, and each day thereafter until the test or
evaluation was completed. This complied with the terms of the consent decree.
Defendant argues that the testing and evaluation requirements are discrete, not continuing
violations, citing cases that discuss the continuing violation theory in the context of the statute of
limitations.105 But the stipulated penalties are imposed under the 2012 CD, and its language
controls how stipulated penalties are calculated. The Court finds that the 2012 CD
unambiguously provides that stipulated penalties “shall continue to accrue until performance is
satisfactorily completed or until the violation ceases.”106 Unlike the regulation at issue in Trident
Seafoods Corp., the 2012 CD, to which the parties agreed to be bound, provides that the penalty
will continue to accrue until either performance is satisfactorily completed or until the violation
ceases.107 Plaintiffs demanded stipulated penalties for each day that accrued after the violation
103
Id. ¶ 202.
104
See id. ¶¶ 190.b, 192.b, 192.c, 194, 196, 198.a.
105
See United States v. Reitmeyer, 356 F.3d 1313, 1321 (10th Cir. 2004) (considering whether a criminal
offense is “continuing” for purposes of the statute of limitations); Toussie v. United States, 397 U.S. 112, 115 (1970)
(same); United States v. Trident Seafoods Corp., 60 F.3d 556, 559 (9th Cir. 1995) (considering whether the
defendant’s failure to give advance notice of the company's intent to remove asbestos was a continuing violation
under the CAA and implementing regulations and finding that the language of the regulation failed to give notice
that the violation would trigger a penalty “based on the length of time that the breach exists”); United States v.
Midwest Generation, LLC, 720 F.3d 644, 647 (7th Cir. 2013) (considering whether failure to obtain a construction
permit was a continuing violation for purposes of the CAA’s statute of limitations based on the language of the
statute and implementing regulation).
106
Doc. 14 ¶ 202.
107
See Trident Seafoods Corp., 60 F.3d at 559.
41
until performance was satisfactorily completed. This complied with the unambiguous terms of
the consent decree.
C.
Merits-Based Challenges to Alleged Subpart Ja Violations
1.
Flow Monitors, Claims 3–4
40 C.F.R. § 107a(f) required Defendant to “install, operate, calibrate and maintain, in
accordance with the specifications in paragraph (f)(1) of this section, a [continuous parameter
monitoring system] to measure and record the flow rate of gas discharged to the flare.” The
parties agree that Defendant installed flow monitors at the Coker and CWP flares on November
3, 2015, in order to comply with this provision, which became effective on November 11, 2015.
Plaintiffs allege that Defendant failed to measure and record the flow of gas discharged at the
flares from November 11, 2015 until October 21, 2016 at the Coker flare, and until April 14,
2017 at the CWP flare. Defendant contends that despite “operational issues” it experienced with
the flow monitors on the dates at issue, it complied with 40 C.F.R. § 107a(f).
According to Defendant’s Environmental Manager, John Ditmore, after the new flow
monitors were installed in November 2015, Defendant experienced issues with them
communicating data to the Refinery’s data historian (Pi System) and data acquisition system
(“DAS”), which store operating data and information monitored by various equipment, including
CEMSs, installed throughout the Refinery. Ditmore asserts that the primary cause of these issues
was the use of an analog signal that caused anomalies in the transmission of data between the
DAS and the flow meters. Defendant subsequently switched this signal from analog to digital to
help address these issues. And General Electric, the manufacturer of the Panametric flow
meters, visited the Refinery on several occasions in November 2015, July 2016, August 2016,
and October 2016 to install, calibrate, and/or perform maintenance on the flow meters.
42
Plaintiffs counter that Defendant’s many reports submitted to Plaintiffs in 2016 and 2017
support its allegation that the flow monitors were not measuring and recording the flow rate of
gas discharged to the flares. For example, in a December 2017 NSPS Subpart Ja Semiannual
Report, Defendant admitted that “ongoing issues with the Cold Water Pond Flare flow meters”
meant that “data is not available to accurately and/representatively report on the flow during that
discharge duration.”108
The reports attached to Peterson’s declaration demonstrate that Defendant’s issues with
the flow meters went beyond mere communication problems and impacted the flow meters’
ability to measure and record the flow rate of gas discharged to the flare as required by the
regulation. Moreover, to the extent Defendant argues that by seeking maintenance from General
Electric and switching the flow meters’ analog signal to digital constitutes substantial
compliance, it does not excuse CAA violations or Plaintiffs’ right to demand stipulated penalties
under the 2012 CD. There is no provision in the regulation or the consent decree that excuses
performance based on a finding of substantial compliance.109 Defendant’s challenge to
Plaintiffs’ stipulated penalty demands on Claims 3 and 4, based on a violation of 40 C.F.R. §
107a(f), is therefore denied.
108
Doc. 81-7 at 2; see also Doc. 81-3 at 4; Doc. 81-4 at 2; Doc. 81-5 at 2, 4.
109
See Pound v. Airosol Co., 498 F.3d 1089, 1097 (10th Cir. 2007) (stating that the CAA imposes strict
liability for violations of the Act); United States v. B & W Inv. Props., 38 F.3d 362, 367 (7th Cir. 1994) (same).
43
2.
Claims Based on Untimely Compliance with Tests and Evaluations,
Claims 5–6, 13–14, and 15–16
Claims 5–6, 13–14, and 15–16 allege untimely compliance with certain performance tests
and evaluations required under Subpart Ja for H2S and TRS monitors located at the Coker and
CWP flares.110
a.
Claims 5 and 6
First, under 40 C.F.R. § 60.104a(a):
The owner or operator shall conduct a performance test for
each . . . fuel gas combustion device to demonstrate initial
compliance with each applicable emissions limit in § 60.102a and
conduct a performance test for each flare to demonstrate initial
compliance with the H2S concentration requirement in §
60.103a(h) according to the requirements of § 60.8.
Under § 60.8(a), “not later than 180 days after initial startup of such facility . . . the owner or
operator of such facility shall conduct performance test(s) and furnish the Administrator a
written report of the results of such performance test(s).” Claims 5 and 6 allege that Defendant
failed to conduct a performance test within 180 days “after initial startup of such facility.”
Plaintiffs maintain that initial startup at the CWP and Coker flares occurred when they were
modified, which triggered Subpart Ja applicability. Because the flares became subject to Subpart
Ja on November 11, 2015, at the latest, Plaintiffs maintain that Defendant was required to
conduct these performance tests by May 9, 2016. Defendant did not conduct the tests until
October 25, 2016 at the Coker flare and June 8, 2017 at the DWP flare.
110
The stipulated penalties Plaintiffs demand on these claim are suspended, as they are asserted to be
subsumed claims in whole or in part. The Court nonetheless rules on these claims in the event Plaintiffs withdraw
their primary claims on these dates and to ensure a complete record.
44
Under Subpart Ja, “[s]tartup means the setting in operation of an affected facility for any
purpose.”111 And “[a]ffected facility means, with reference to a stationary source, any apparatus
to which a standard is applicable.”112 As Plaintiffs argue, the CWP and Coker flares did not
become an “affected facility” for purposes of Subpart Ja until they were modified in 2014. EPA
published in the preamble to its final rule on NSPS Subpart Ja its construction of how “startup”
applies to modified flares:
For the purposes of this subpart, startup of the modified flare
occurs when any of the activities in 40 CFR 60.100a(c)(1) or (2) is
completed (e.g., when a new connection is made to a flare such
that flow from a refinery process unit or ancillary equipment can
flow to the flare via that new connection).113
Based on this guidance and the plain meaning of the regulation, Plaintiffs contend they used the
latest possible date for Subpart Ja applicability as November 11, 2015, for purposes of
calculating the performance test deadline. The Court agrees that EPA’s guidance is consistent
with the plain meaning of the applicable regulations.
Defendant argues that under § 60.8, because the flares are “existing” facilities, any
“deadline for a performance test tied to their initial startup is clearly inapplicable.”114 The
problem with Defendant’s interpretation of § 60.8 is that it reads out of the definition of “startup”
the term, “affected facility,” and reads into the regulation the word “existing.” The flares were
not an “affected facility” until they were modified, triggering Subpart Ja. The fact that they
“existed” before this modification is not relevant under the plain terms of the regulations, which
111
40 C.F.R. § 60.2.
112
Id.
113
Standards of Performance for Petroleum Refineries; Standards of Performance for Petroleum Refineries
for Which Construction, Reconstruction, or Modification Commenced After May 14, 2007, 77 Fed. Reg. 56422-01,
56,451 & n.11 (Sept. 12, 2012).
114
Doc. 64 at 25 (emphasis in original).
45
references “initial startup of an affected facility.” To be sure, as Defendant points out, the word
“initial” is not defined and the flares existed before they were modified in 2014. But the plain
meaning of the word “initial,” is “placed at the beginning: FIRST.”115 Thus, under the terms of
the regulation, most of which are defined, “initial startup of an affected facility” means the “the
first setting in operation of any apparatus to which a standard is applicable for any purpose.”
Under this definition, the flares first became an “affected facility” when they were modified,
which made Subpart Ja applicable for the first time. Under the plain and unambiguous terms of
the regulation, Plaintiffs used a conservative estimate of November 11, 2015, for purposes of
Subpart Ja applicability, and the Court therefore finds no error in tying the initial performance
test deadline to this date.
Plaintiffs’ interpretation of these performance test regulations is also in keeping with their
purpose, which would be undermined by Defendant’s interpretation.116 The clear purpose of the
performance test requirement is to demonstrate that the flares are in compliance with the H2S
concentration limit in 40 U.S.C. § 60.103a(h).117 To find that there is no deadline to demonstrate
compliance undermines the stated purpose of the emission and testing requirements.
Defendant argues that the regulation does not provide it with notice about the deadline
that applied to conducting performance tests on its flares, and that EPA knows how to establish
clear guidance about compliance deadlines but opted not to here. But this argument ignores the
115
Initial, Merriam-Webster, https://www.merriam-webster.com/dictionary/initial (last visited March 8,
2022).
116
Kisor v. Wilkie, 139 S. Ct. 2400, 2415 (2019) (explaining that the Court must “carefully consider[ ]” the
text, structure, history, and purpose of a regulation, in all the ways it would if it had no agency to fall back on”
(quoting Pauley v. BethEnergy Mines, Inc., 501 U.S. 680, 707 (1991) (Scalia, J., dissenting))).
117
See 40 C.F.R. § 60.104a(a) (“The owner or operator shall conduct a performance test for each . . . fuel
gas combustion device to demonstrate initial compliance with each applicable emissions limit in § 60.102a and
conduct a performance test for each flare to demonstrate initial compliance with the H2S concentration requirement
in § 60.103a(h) according to the requirements of § 60.8.”).
46
clear guidance provided in the definitions section of the regulation, as well as published EPA
guidance, as described above. Defendant’s conclusory assertion that the EPA’s published
guidance is merely “regulatory history” is unavailing. First, Defendant’s position is not merely
tied to “regulatory history.” It is based on the text of the regulation and its definitions that
squarely apply when construing the performance test standards at issue here. The Court has
found that the plain meaning of the regulation, when read in conjunction with the regulation’s
definitions provision, is not ambiguous. Second, the EPA’s construction has been published in
the Federal Register since 2012, so any argument that Defendant lacked notice of the applicable
deadline, even assuming that it misinterpreted the regulation’s text, is unavailing. The Court,
therefore, grants Plaintiffs’ stipulated penalty demand in Claims 5 and 6 to the extent they are
not subsumed by other violations.
b.
Claims 13–14
Second, under 40 U.S.C. § 60.107a(a)(2)(ii), Defendant was required to “conduct
performance evaluations for each H2S monitor according to the requirements of § 60.13(c) and
Performance Specification 7 of appendix B to part 60.” Section 60.13(c) in turn requires
performance evaluations “during any performance test required under § 60.8 or within 30 days
thereafter.” Therefore, Plaintiffs maintain in Claims 13 and 14 that Defendant was required to
conduct a performance evaluation at least 30 days after the initial performance test, or by June 8,
2016. Instead, Defendant conducted its performance evaluations under this Subpart Ja provision
on October 25, 2016.
Defendant’s only challenge to the untimely evaluation claims in Claims 13 and 14 is
based on the same deadline challenge to Claims 5 and 6—since the evaluation deadlines are tied
to the deadlines for the performance tests, there is no deadline for these evaluations. For the
47
same reasons stated above, the Court finds that the performance tests were due within 180 of
November 11, 2015, and therefore the evaluations were due 30 days after the performance tests.
There is no dispute that Defendant failed to complete the performance evaluations by this
deadline, so Plaintiffs have demonstrated the violations in Claims 13 and 14 by a preponderance
of the evidence. The Court, therefore, grants Plaintiffs’ stipulated penalty demand in Claims 13
and 14, to the extent they are not subsumed by other violations.
c.
Claims 15–16
Finally, under 40 U.S.C. § 60.107a(e)(1)(ii), Defendant was required to “conduct
performance evaluations of each total reduced sulfur monitor according to the requirements in
§ 60.13(c) and Performance Specification 5 of appendix B to this part.” Like the performance
evaluations for the H2S monitors, § 60.13(c) requires these performance evaluations “during any
performance test required under § 60.8 or within 30 days thereafter.” Because Defendant was
required to conduct a performance test for each flare to demonstrate initial compliance with the
H2S concentration requirement in § 60.103a(h) according to the requirements of § 60.8 by May
9, 2016 at the latest, Plaintiffs maintain that performance evaluations on the TRS monitors at the
flares were due by June 8, 2016. Defendant did not conduct these performance evaluations until
October 25, 2016.
First, Defendant challenges Claims 15 and 16 to the extent the deadline is tied to the H2S
monitor performance tests alleged in Counts 5 and 6. To the extent Defendant argues that no
deadline applies to these evaluations because no deadlines applied to the performance tests, the
Court rejects this argument for the same reasons explained above on Claims 5 and 6.
Defendant additionally argues that there is no requirement under the regulations that it
conduct performance evaluations on the TRS monitors because there is no requirement for an
48
initial test of those monitors like there is for the H2S monitors. But the Court finds that
Plaintiffs’ interpretation of the regulations pertaining to the TRS performance evaluation
requirement and deadline is consistent with a plain reading of the regulations, particularly when
they are read together. The purpose of the TRS monitor evaluation is different than that for the
H2S monitor evaluation, which was to determine compliance with emission limits. Under
§ 60.107a(e), sulfur monitoring is “for assessing root cause analysis threshold for affected
flares.” Therefore, Defendant’s suggestion that a follow-up evaluation is not needed for the TRS
monitors here because no initial test was conducted, is misplaced when considering the stated
purpose of the regulation.
Moreover, Defendant’s assertion that Plaintiffs’ interpretation of the regulation would
require it to “conduct multiple, redundant performance evaluations on the flare TRS analyzers
any time a performance test is conducted on any of these other process units at the refinery,”118 is
not a fair reading of either the regulations or Plaintiffs’ position. Section § 60.107a(e)(1)(ii)
requires a performance evaluation on the TRS monitor according to the requirements in
§ 60.13(c), which in turn requires performance evaluations “during any performance test
required under § 60.8 or within 30 days thereafter.” Plaintiffs do not argue that any performance
test under § 60.8 triggered Defendant’s obligation to conduct a TRS analyzer performance
evaluation. Instead, they claim that Defendant was separately obligated to conduct performance
tests on the H2S analyzers, and that those performance tests triggered the deadline for the
performance evaluations on the TRS monitors at the flare headers, which are located in the same
process unit at the Refinery as the H2S monitors. Defendant fails to identify any performance
118
Doc. 64 at 38.
49
test required to be conducted at “other process units at the refinery” that would trigger the TRS
analyzer performance evaluations at issue on these claims.
Accordingly, the Court finds that the regulations unambiguously required Defendant to
conduct these TRS analyzer performance evaluations by June 8, 2016. Because there is no
question that Defendant failed to meet this deadline, the Court grants Plaintiffs’ stipulated
penalty demand in Claims 15 and 16 to the extent they are not subsumed by other violations.
3.
Span Value for Flare TRS Analyzers, Claims 11-12
In Claims 11 and 12, Plaintiffs demand stipulated penalties for Defendant’s violation of
40 U.S.C. § 60.107a(e)(1)(i), which governs the appropriate span value for its TRS analyzers.119
The span value is “[t]he upper limit of a gas concentration measurement range that is specified
for affected source categories in the . . . regulation.”120 Subpart Ja states that the span value on a
TRS analyzer “should be determined based on the maximum sulfur content of gas that can be
discharged to the flare (e.g., roughly 1.1 to 1.3 times the maximum anticipated sulfur
concentration), but may be no less than 5,000 ppmv.”121
Between November 11, 2015 and April 30, 2016, Defendant used a span value of
200,000 ppm, or 20%.122 Plaintiffs maintain that this span value did not comply with
§ 60.107a(e)(1)(ii) because during that time period the maximum sulfur content that could be
discharged to the flares was not less than 18.2%. Defendant responds that in 2016, the EPA
119
The stipulated penalties Plaintiffs demand on these claim are suspended, as they are all asserted to be
subsumed claims. The Court nonetheless rules on these claims in the event Plaintiffs withdraw their primary claims
that apply to these dates and to ensure a complete record.
120
40 C.F.R. Pt. 60, App. F, Procedure 1, § 2.3.
121
40 C.F.R. § 60.107a(e)(1)(i).
122
The parties vacillate between discussing the span value and sulfur concentration measurements in terms
of a percentage and parts per million (“ppm”). A 1% sulfur concentration equates to 10,000 ppm. Thus, 20% sulfur
concentration is the same as 200,000 ppm. Doc. 80, Sahu Decl. ¶ 35. The Court will generally reference the span
value in terms of a percentage going forward.
50
“demanded” that it set its span values at 100%, which was based on an incorrect reading of the
regulation and of the analyzers’ historical data, which showed “virtually no instances” of the
TRS analyzers on either flare recording sulfur concentrations above 20%. Defendant complains
that in an effort to avoid an enforcement action, it voluntarily increased the span values, but
maintains that based on sampling, its own engineering judgment, and knowledge of the Refinery
units and flow, its original setting of 20% was correct and in compliance with the regulation.
Once again, the parties have differing interpretations of the regulation. Defendant argues
that the maximum sulfur content should not be determined based on the mere possibility of a
certain maximum sulfur concentration, particularly given that the TRS analyzers’ data shows that
sulfur concentrations were less than 20% for more than 99% of all hours during the timeframe of
November 11, 2015 and June 30, 2018. Defendant focuses on the word “anticipated,” which it
contends means “expected or looked-forward to.”123 Given the data, Defendant maintains that
the “maximum anticipated sulfur concentration” was “clearly” less than 20% and nowhere near
the 100% value it set in 2016 in response to the EPA’s request for information.124
Plaintiffs respond that Defendant misreads the regulation by placing too much emphasis
on the word “anticipated” and reading out the word “maximum.” The Court agrees, and finds
that Defendant’s interpretation also reads out of the regulation the term “can be.” The regulation
states that the span value is “determined based on the maximum sulfur content of gas that can be
discharged to the flare.” The word “maximum” is defined as “the greatest quantity or value
attainable or attained.”125 “Can” in this context is “used to indicate possibility . . . sometimes
123
Anticipated, Merriam-Webster, https://www.merriam-webster.com/dictionary/anticipated (last visited
Mar. 9, 2022).
124
Doc. 84 at 21.
125
Maximum, Merriam-Webster, https://www.merriam-webster.com/dictionary/anticipated (last visited
Mar. 9, 2022).
51
used interchangeably with may” or to mean “logically or axiologically able to.”126 Therefore, the
plain language of the regulation requires the span value to be determined based on the greatest
value attainable or attained that may be discharged to the flare.
Within the same sentence, immediately following this language, the regulation contains a
parenthetical that states “e.g., roughly 1.1 to 1.3 times the maximum anticipated sulfur
concentration.” The parenthetical belongs to the sentence in which it is embedded, providing
the span value based on specific multipliers. It again uses the term “maximum,” but this time
adds “anticipated.” Thus, when read together, the span value is determined based on the greatest
value attainable or attained that may be discharged to the flare, which should be specifically
calculated as “roughly 1.1 to 1.3 times” the “greatest quantity attainable” of “expected” sulfur
concentration. The parenthetical does not change the meaning of the sentence it belongs to, nor
does it permit an estimated maximum sulfur concentration that disregards the maximum possible
sulfur concentration that can be discharged to the flares. Moreover, Plaintiffs’ interpretation is in
keeping with the purpose of the regulation, which is to “quantify[] the concentrations of highsulfur-containing streams as these would be the streams most likely to trigger a root-cause
analysis.”127 Because the No. 3 Sulfur Recovery Unit (“SRU #3”) was reported by Defendant on
August 29, 2016 to have had a maximum H2S concentration of 87%, Plaintiffs maintain this was
the maximum sulfur content of gas that can be discharged to the flare and, therefore, span value
should have been set at 1.1 to 1.3 times this amount.128
126
Can, Merriam-Webster, https://www.merriam-webster.com/dictionary/anticipated (last visited Mar. 9,
2022).
127
Standards of Performance for Petroleum Refineries for Which Construction, Reconstruction, or
Modification Commenced after May 14, 2007, 77 Fed. Reg. 56422-01, 56,449 (Sept. 12, 2012).
128
Doc. 81-11 at 17.
52
Defendant advances several arguments about why the span values should not be based on
this 87% maximum concentration figure, and repeatedly argues that a 100% span value is not
appropriate because the 87% value was either diluted by commingling with other gas streams, or
occurred so rarely that it was not anticipated and therefore shouldn’t be used to determine the
span value. Defendant claims its data shows that the maximum sulfur concentration recorded by
the analyzers was below 20% for more than 99% of the time during the period November 11,
2015 to June 30, 2018.
Plaintiffs have demonstrated by a preponderance of the evidence that Defendant’s 20%
span value on the dates in question was too low, and therefore did not comply with the
regulation. First, Defendant argues that even if it is possible for some of the gas streams to have
sulfur concentrations in excess of 20%, other process streams commingled with them to dilute
the ultimate sulfur concentration of gases combusted at the flares. It contends that because only
the comingled stream is discharged to the flares, high-sulfur-producing gas streams are not an
appropriate maximum concentration measurement for purposes of span value. But Plaintiffs
factored this into their request for information that led to a finding that the span value
measurements were too low. EPA responded to this exact argument by Defendant on April 22,
2016:
Given the high level of sulfur in some of the process streams that
can be routed to the flare headers, EPA maintains that the current
TRS span value of 20% on both flares is likely too low. The
variation of process stream sulfur concentration, flowrate, and
baseline flowrates in each of the corresponding flare headers
impact the span values; this information is needed to ensure the
monitors are properly spanned and therefore, EPA is unwilling to
withdraw the Information Request.129
129
Doc. 81-10 at 3.
53
Dr. Sahu provided several calculations in his declaration based on actual data provided by
Defendant, showing examples of how a high maximum sulfur concentration reported by
Defendant, even when taking into account dilution from other gas streams with lower
concentrations, necessitated a span value of more than 20%.130 Specifically, he calculated the
span value based on the SRU #3 87% value and found that even accounting for the baseline flow
and H2S concentration in the flare after comingling, the span value should have been set at
between 79% or 100%, depending on whether he used the baseline flow rate from 2015 or 2020.
Either way, 20% was far too low.
Defendant asserts in its briefing that “actual operating data shows that the TRS analyzers
never recorded concentrations above 200,000 ppm,” so it could not have “anticipated” that gas
streams in excess of that amount could be discharged to the flares.131 There are several glaring
errors with this statement. First, as Defendant’s footnote immediately following this sentence
admits, it is not true that the monitors “never” recorded concentrations above 200,000 ppm.
Defendant admits that there were “hours in which the TRS analyzers did record sulfur
concentrations in excess of 200,000 ppm that occurred prior to the date the analyzers were
certified, during analyzer calibrations, when the analyzers had failed a calibration, or during a
cylinder gas audit.”132 Second, the regulation plainly does not require Defendant to determine
what the “representative” amount of sulfur concentration discharged to the flares is in order to
determine span value and disregard high sulfur concentration readings based on its own
unilateral engineering judgment. And third, because the regulation requires a span value of 1.1
to 1.3 times the maximum sulfur concentration that can be discharged to the flares, Defendant’s
130
Doc. 80, Sahu Decl. ¶¶ 37–40.
131
Doc. 84 at 23 (emphasis in original).
132
Id. n.12.
54
assertion that the TRS analyzers did not record concentrations above 200,000 ppm would still
not demonstrate that a 20% span value was correct. Even if the maximum sulfur concentration
was 20%, the span value would be 1.1 to 1.3 times that amount.
Finally, Defendant’s assertion that there were “virtually no instances in which the TRS
analyzers on either flare recorded TRS concentrations” that required a span value higher than
20% is not sufficient to show regulatory compliance. The regulation’s span value determination
is not based on the “representative” amount of sulfur concentration, nor does it allow for the
Refinery to discount actual data that it unilaterally determined was either not accurate or an
errant, rarely captured measurement. The regulation requires the span value to be based on the
maximum sulfur content of gas that can be discharged to the flare; not the amount that was
actually discharged. The Court finds that Plaintiffs have shown by a preponderance of evidence
that, even discounting the SRU #3 measurement, there were several days in 2016 where the TRS
analyzers at the flares recorded sulfur concentrations that should have triggered a span value in
excess of 20%.133 As such, Plaintiff’s petition to review claims 11 and 12 is denied and
Plaintiffs’ stipulated penalty demands are granted, to the extent they are not subsumed by other
claims.
V.
Conclusion
Defendant seeks judicial review of Plaintiffs’ stipulated penalty demand for $6,817,000
based on violations of paragraphs 60 and 61 of the 2012 CD. The Court has considered multiple
rounds of briefing, along with the parties’ attached exhibits, on Defendant’s many legal and
factual challenges to the alleged violations. For the reasons explained throughout this opinion,
Defendant’s petition for review is denied to the extent it asks this Court to find that it did not
133
Doc. 80, Sahu Decl. ¶ 42.
55
violate the 2012 CD. The petition is further denied to the extent it asks the Court to dismiss or
reduce Plaintiffs’ stipulated penalty demand due as a result of those violations.
IT IS THEREFORE ORDERED BY THE COURT that Defendant’s Petition for
Judicial Review (Doc. 40) is denied.
IT IS SO ORDERED.
Dated: March 30, 2022
S/ Julie A. Robinson
JULIE A. ROBINSON
UNITED STATES DISTRICT JUDGE
56
Disclaimer: Justia Dockets & Filings provides public litigation records from the federal appellate and district courts. These filings and docket sheets should not be considered findings of fact or liability, nor do they necessarily reflect the view of Justia.
Why Is My Information Online?