The Babcock & Wilcox Company et al v. Philadelphia Energy Solutions Refining and Marketi

UNITED STATES BANKRUPTCY COURT
EASTERN DISTRICT OF LOUISIANA
IN RE:
THE BABCOCK & WILCOX
COMPANY,
DEBTOR.
§
§ CASE NO: 00-10992
§
§ CHAPTER 11
§
§ SECTION A
§
THE BABCOCK & WILCOX
COMPANY,
PLAINTIFF,
V.
PHILADELPHIA ENERGY SOLUTIONS
REFINING AND MARKETING LLC,
PES LIQUIDATING TRUST,
WESTPORT INSURANCE COMPANY,
XL INSURANCE AMERICA, INC.,
ALLIANZ GLOBAL RISKS US
INSURANCE COMPANY, HDI GLOBAL
INSURANCE COMPANY, AND
CERTAIN UNDERWRITERS AT
LLOYD’S LONDON-SYNDICATE 1221
(NAVIGATORS), ZURICH AMERICAN
INSURANCE COMPANY, CERTAIN
UNDERWRITERS AT LLOYD’S
SUBSCRIBING TO ENNMG1800181,
CERTAIN UNDERWRITERS AT
LLOYD’S SUBSCRIBING TO
ENNMG1800281, CERTAIN
UNDERWRITERS AT LLOYD’S
SUBSCRIBING TO ENNMG1800282,
CERTAIN UNDERWRITERS AT
LLOYD’S SUBSCRIBING TO EN100070-
18,
DEFENDANTS.1
§
§
§
§
§
§ ADV. NO. 21-1014
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
§
1 On October 24, 2023, the following entities were allowed to intervene as plaintiffs in this adversary
proceeding: (i) Westchester Fire Insurance Company; (ii) Ace Property & Casualty Insurance Company;
(iii) Indian Harbor Insurance Company; (iv) Starr Surplus Lines Insurance Company; and (v) The Members
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 1 of
47

2
MEMORANDUM OPINION AND ORDER
The sole count in the above-captioned adversary proceeding filed by The Babcock &
Wilcox Company (pre-confirmation, “B&W” and, post-confirmation, the “Reorganized B&W”)
seeks (i) a declaration that the confirmed joint plan of reorganization in B&W’s 2000 bankruptcy
case discharged the claims now asserted against the Reorganized B&W and affiliates in a
Pennsylvania state court by two of the above-named Defendants, Philadelphia Energy Solutions
Refining & Marketing, LLC (“PESRM”), and PES Liquidating Trust (together, with PESRM, the
“PES Entities”) and (ii) enforcement of the confirmed joint plan’s discharge injunction. Through
the Pennsylvania state court action, the PES Entities assert products-liability claims against the
Reorganized B&W entities stemming from a 2019 explosion at a refinery formerly operated by
PESRM (the “Girard Point Refinery”) allegedly caused by the failure of an elbow joint
manufactured by B&W and installed in the hydrofluoric-acid alkylation unit in the refinery in the
early 1970s.
After denying cross-motions for summary judgment as well as a second motion for
summary judgment filed by the Reorganized B&W, [ECF Docs. 199 & 236], this Court held a
four-day trial on the merits of the sole count alleged in the adversary proceeding. The Court heard
testimony and admitted exhibits identified in its Order dated April 17, 2025. [ECF Doc. 258]; see
also [ECF Doc. 268]. The Court accepted post-trial briefs from the parties, [ECF Docs. 269, 270,
274 & 275], and took the matter under advisement, [ECF Doc. 284].
Pursuant to Bankruptcy Rule 7052, the Court issues the following findings of fact and
conclusions of law. Based on the evidence and applicable law, the Court finds that the PES Entities
of Lloyd’s Syndicate 1861 as constituted for the 2019 underwriting year of account acting through their
managing agent Canopius Managing Agents Limited (collectively, the “Reorganized B&W Insurers”). The
Reorganized B&W Insurers did not participate in the trial.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 2 of
47

3
have met their burden to show that their products-liability claims are not prepetition bankruptcy
claims discharged by the confirmed joint plan in B&W’s bankruptcy case; therefore, they are
excepted from the consequences of that confirmed plan. The Court thus DENIES the sole count
in the Reorganized B&W’s declaratory action.2
JURISDICTION
This Court has jurisdiction to grant the relief provided for herein pursuant to 28 U.S.C.
§ 1334 and the matter presently before the Court constitutes a core proceeding that this Court may
hear and determine on a final basis under 28 U.S.C. § 157(b). See U.S. Brass Corp. v. Travelers
Ins. Grp., Inc. (In re U.S. Brass Corp.), 301 F.3d 296, 303–06 (5th Cir. 2002). Further, the
confirmed joint plan of reorganization in this case reserves the jurisdiction of this Court “[t]o hear
and determine all controversies, suits, and disputes that may relate to, impact upon, or arise in
connection with this Plan or any other Plan Documents or their interpretation, implementation,
enforcement, or consummation” and “[t]o hear and determine any other matters related hereto,
including matters related to the implementation and enforcement of all orders entered by the Court
in [B&W’s] Chapter 11 Cases,” which includes the Order confirming the joint plan of
reorganization. [No. 00-10992, ECF Doc. 7059, §§ 9.5.3 & 9.5.9]; see also [No. 00-10992, ECF
Doc. 7053].
2 The application of the Court’s findings of fact herein is limited to the sole issue of whether the PES
Entities’ products-liability claims are prepetition bankruptcy claims that were discharged by B&W’s
confirmed joint plan of reorganization.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 3 of
47

4
PART I: FINDINGS OF FACT3
Specific Witness Credibility Determinations
Anthony Rutkowski, a corrosion engineer, spent his 37-year career at the Girard Point
Refinery, starting in 1969. See Trial Tr. 46:2–6 (Apr. 7, 2025), [ECF Doc. 262]. He served as a
refinery-piping inspector and supervisor in the hydrofluoric-acid alkylation unit between 1994 and
2001 and holds several certifications from the American Petroleum Institute specific to refinery
and piping inspection. See Trial Tr. 46:7–49:14 (Apr. 7, 2025). The Court finds Mr. Rutkowski’s
testimony to be credible and useful to the Court regarding the use of thickness-measurement
locations to measure corrosion rates in the refinery’s piping system and the results of thickness-
measurement location reports in the hydrofluoric-acid alkylation unit from the late 1990s to early
2000s.
Gary Kemeny, a chemical engineer, was employed by Gulf Oil in 1978 at the Girard Point
Refinery and worked in the hydrofluoric-acid alkylation unit of the refinery in various capacities
between 1982 and 1987, 1992 to 1997, and 2005 to 2019. See Trial Tr. 102:22–105:1, 106:12–
111:16 (Apr. 8, 2025), [ECF Doc. 263]. His roles primarily involved operations and supervision
of operators and inspectors in Unit 433; he served as the lead process engineer for a major
modification of the hydrofluoric-acid alkylation unit in 2010 and as the alkylation engineering
advisor for the refinery through 2019. See id. He has served on nationwide ad hoc committees of
hydrofluoric-acid alkylation unit operators and has contributed to the American Petroleum
Institute’s recommended practices for the safe operation of hydrofluoric-acid alkylation units. See
3 To the extent that any of the following findings of fact are determined to be conclusions of law,
they are adopted and shall be construed and deemed conclusions of law. To the extent any of the following
conclusions of law are determined to be findings of fact, they are adopted and shall be construed and deemed
as findings of fact.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 4 of
47

5
Trial Tr. 105:2–20 (Apr. 8, 2025). Mr. Kemeny oriented the Court as to the process flow in the
Girard Point Refinery’s hydrofluoric-acid alkylation unit, see Trial Tr. 113:18–145:7 (Apr. 8,
2025), and provided results from the PES Entities’ internal investigation after the June 2019
incident at the refinery, having played an integral part on the investigation team, see Trial Tr.
105:21–106:11; 162:20–167:14; 194:17–195:25 (Apr. 8, 2025). The Court finds Mr. Kemeny to
be a credible fact witness and gives much weight to his testimony, particularly as it relates to
recommended inspection protocols for hydrofluoric-acid alkylation unit piping systems over the
years and the inspection protocols that were implemented in the Girard Point Refinery.
Glen Stevick, Ph.D., a mechanical engineer and the principal and founder of Berkeley
Engineering and Research, Inc., provided expert testimony on behalf of the Reorganized B&W at
trial. Dr. Stevick serves on several committees associated with the American Society of
Mechanical Engineers and is a member of the American Society for Civil Engineers and the
Society of Forensic Engineering. See Trial Tr. 49:13–50:12 (Apr. 10, 2025), [ECF Doc. 264]. But
Dr. Stevick is not a metallurgical engineer and has little practical experience working in
hydrofluoric-acid environments or designing positive-material identification programs or Project
Safety Management programs (discussed infra). See Trial Tr. 216:12–235:17 (Apr. 10, 2025). Dr.
Stevick opined as to why the elbow joint manufactured by B&W for installation in the
hydrofluoric-acid unit at the Girard Point Refinery in the early 1970s complied with the American
Society for Testing and Materials’ chemical composition requirements at that time, asserting that
substitutions were commonplace given engineering’s focus on “the cost, what’s practical,
generally accepted good engineering practices.” See Trial Tr. 57:21–58:11; 238:18–249:9 (Apr.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 5 of
47

6
10, 2025).4 After asserting that the elbow joint met chemical specifications at installation, Dr.
Stevick further opined as to Sunoco’s knowledge of the dangers associated with elevated levels of
residual elements nickel and copper in carbon-steel piping and testified that industry best practices
in the mid-1990s to 2003 obligated Sunoco to inspect every single component part in the
hydrofluoric acid alkylation unit retroactively—while again acknowledging high costs and
practical concerns for such measures. See Trial Tr. 58:12–59:22; 61:6–64:10; 117:13–123:9 (Apr.
10, 2025) (“[E]ngineering is always involved heavily with cost [and] [w]e can’t just design things
without consideration of how much they cost . . . .”). The Court finds Dr. Stevick’s testimony to
be incongruent and strained and gives little weight to his testimony.
Robert A. Carnahan, a metallurgical engineer, provided expert testimony in the areas of
metallurgy, corrosion, and failure analysis and prevention. Mr. Carnahan is a current member of
several professional organizations, including the Association for Materials and Protection
Performance (f/k/a the National Association of Corrosion Engineers) and the American Society
for Testing and Materials. See Trial Tr. 92:21–93:2 (Apr. 11, 2025), [ECF Doc. 265]. He has
worked on projects with Anamet Labs, a metallurgical-testing laboratory specializing in failure
analysis and mechanical testing, and assisted Anamet Labs in its investigation of the causes of the
June 2019 explosion at the Girard Point Refinery. See Trial Tr. 107:16–108:12 (Apr. 11, 2025).
Mr. Carnahan offered expert opinion specifically on applicable American Society for Testing and
Materials standards, changing methods for steel production in this country affecting the resiliency
of piping systems used in hydrofluoric-acid environments, and the corrosive effects of hydrofluoric
acid on steel containing high amounts of residual elements. The Court finds Mr. Carnahan to be a
4 That opinion may be relevant to determining whether the Reorganized B&W has any products
liability on account of the failed elbow joint, but it is not helpful to this Court in deciding whether those
claims are prepetition bankruptcy claims discharged by B&W’s confirmed joint plan of reorganization.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 6 of
47

7
knowledgeable and direct witness, and his testimony to be most useful to the Court in deciding the
issues before it. The Court gives maximum weight to his testimony.
Steve Arendt, a retired nuclear engineer, has consulted refinery operators in the areas of
process safety and major accident prevention since 1978. See Trial Tr. 323:5–325:13 (Apr. 10,
2025). Having long served on working groups to develop and implement chemical accident
prevention regulations issued by the U.S. Department of Labor Occupational Safety and Health
Administration and the United States Environmental Protection Agency, Mr. Arendt provided the
Court with expert testimony on such. See Trial Tr. 325:8–334:10 (Apr. 10, 2025). He also
provided the Court with an excellent overview and explanation of the meaning of the engineering
term of art, “RAGAGEP,” a term he coined for “recognized and generally accepted good
engineering practices” and its application in developing refinery safety protocols. See Trial Tr.
334:11–345:19 (Apr. 10, 2025). On those subjects, the Court finds Mr. Arendt to be a reliable,
forthright witness and gives much weight to his testimony.
John Reynolds is a mechanical-integrity engineer with over fifty years’ experience in
refineries. During his career, he focused on inspection and quality assurance of pressure equipment
and implemented inspection and mechanical-integrity standards “to mak[e] sure that the fluids
from an oil refinery stay within the pipes.” Trial Tr. 7:5–25 (Apr. 11, 2025). He has long served
on task groups and subcommittees for the American Petroleum Institute and the American Society
of Mechanical Engineers, taking lead roles for developing recognized and generally accepted good
engineering practices. See Trial Tr. 8:1–6 (Apr. 11, 2025). Mr. Reynolds provided the Court with
expert testimony on the American Petroleum Institute’s recommended practices for mechanical
inspection and corrosion-monitoring in hydrofluoric-acid alkylation units, as well as his opinions
on whether the scope and frequency of piping inspections in the particular circuit housing the
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 7 of
47

8
elbow joint at the Girard Point Refinery complied with recognized and generally accepted good
engineering practices and American Petroleum Institute recommendations during relevant time
periods. See Trial Tr. 8:7–16:10; 48:12–54:10 (Apr. 11, 2025). On those subjects, the Court finds
Mr. Reynolds to be an earnest and reliable witness and gives much weight to his testimony.5
A. Optimal Materials of Construction for Refinery Piping Systems
Alkylation units in refineries are used to convert alkenes to alkylate, a high-octane gasoline
component, using a catalyst such as, in this case, hydrofluoric acid.6 Because alkylation units use
highly hazardous catalysts such as hydrofluoric acid, simply put, piping systems installed in such
units must be designed to keep the fluids within the pipes. See Trial Tr. 53:15–54:22 (Apr. 7,
2025) (Rutkowski); Trial Tr. 7:20–25 (Apr. 11, 2025) (Carnahan). To be clear, corrosion within
the piping systems will occur. But the rate and degree of that environmental degradation is affected
5 Mr. Reynolds also testified regarding the significance of stamps or markings on fittings, including
specific stamps on the elbow joint at issue that were discovered after the June 2019 explosion in Unit 433.
Mr. Reynolds further opined on differences in chemical compositions between Yoloy-brand steel, see infra
note 11, and carbon steel and uses of each. Those opinions may be relevant to determining whether the
Reorganized B&W has any products liability on account of the failed elbow joint, but they are not helpful
to this Court in deciding whether those claims are prepetition bankruptcy claims discharged by B&W’s
confirmed joint plan of reorganization.
6 As described in 1999 by the American Petroleum Institute:
[Hydrofluoric-acid] alkylation is a widely used refinery process important in
producing a significant share of the nation’s high-quality motor gasoline. The acid used in
these units is a hazardous and corrosive liquid which, if accidentally released, can form a
vapor cloud. Contact with HF liquid or vapor can result in serious, painful chemical burns
and adverse health effects, sometimes with delayed onset.
However, with proper design of alkylation units and careful process management,
the acid in these units does not present a significant risk to the community or the
environment. This process has been operated for over 50 years, with only a small number
of incidents affecting the surrounding communities. Moreover, improvements in process
design and management are continually being made to further reduce the risks to workers
and surrounding communities. The petroleum and chemical industries have conducted
extensive research on HY alkylation safety; the results are being used to prevent incidents
and to mitigate the effects of an incident if one occurs.
Joint Ex. 153A, Foreword, [ECF Doc. 253].
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 8 of
47

9
both by the nature, temperature, and velocity of chemicals to which the piping systems are exposed,
and the nature of the materials of which the piping systems are made. See Trial Tr. 96:13–97:24
(Apr. 11, 2025) (Carnahan).
1. Carbon steel has proven optimal for use in hydrofluoric-acid environments.
The American Society for Testing and Materials (“ASTM”) is a long-standing organization
of technical experts that sets standards for, among other things, materials of construction for
refinery piping. See Trial Tr. 24:15–26:22 (Apr. 11, 2025) (Reynolds); Joint Ex. 171 [ECF Doc.
255]. In 1964, the ASTM adopted (and in 1965 revised) a specification numbered “A234”
covering “factory made wrought carbon steel and ferritic alloy steel welding fittings for pressure
piping.” Joint Ex. 171S.7 “Carbon steel” itself is an alloy comprised primarily of iron and carbon,
with other elements present in very low quantities:
The properties of plain carbon steels depend chiefly on their carbon content and
microstructure. . . . [I]n addition to carbon these steels always contain some
manganese, silicon, phosphorus and sulphur: minor amounts of other elements also
may be present. Plain carbon steels, by American Iron and Steel Institute definition,
may contain up to 1.65 per cent manganese, 0.60 per cent silicon and 0.60 per cent
copper in addition to much smaller amounts of other elements.
Joint Ex. 157 (UNITED STATES STEEL, THE MAKING, SHAPING AND TREATING OF STEEL, 1117
(Harold E. McGannon ed., 9th ed. 1971), [ECF Doc. 253]; see also Trial Tr. 106:4–107:15 (Apr.
11, 2025) (Carnahan). ASTM A234 specifies permissible chemical compositions for various
grades of carbon-steel elbow joints. See Joint Ex. 171S, § 4.1 & Table I. Table I of ASTM A234
labeled “Permissible Raw Materials and Marking of Butt-Welding Fittings” invokes ASTM A106
to define the chemical composition that is tolerated for carbon steel. In 1928, the ASTM adopted
7 ASTM Designation A234 application to “welding fittings” includes “butt-welding or socket-ends
parts such as 45 and 90-deg elbows, 180-deg return bends, caps, tees, reducers, lapped joint stub ends, and
other types, as covered by the American Standard for Steel Butt-Welding Fittings (ASA B16.9-1958) and
the American Standard for Steel Socket-Welding Fittings (ASA B16.11-1946).” Joint Ex. 171S.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 9 of
47

10
(and in 1968 revised) a specification numbered “A106” covering “Seamless Carbon-Steel Pipe for
High-Temperature Service.” See Joint Ex. 171B. Table I of the 1968 ASTM A106 is reproduced
here:
TABLE I.—CHEMICAL REQUIREMENTS.
Grade A Grade B Grade C
Carbon, max, per cent………………………………………. 0.25 0.30 0.35
Manganese, per cent………………………………………... 0.27 to 0.93 0.29 to
1.06
0.29 to
1.06
Phosphorus, max, per cent…………………………………. 0.048 0.048 0.048
Sulfur, max, per cent……………………………………….. 0.058 0.058 0.058
Silicon, min, per cent………………………………………. 0.10 0.10 0.10
* Grade C is a special product supplied only on agreement between the manufacturer and the
purchaser.
Thus, ASTM A234 (incorporating ASTM A106) clarifies what “carbon steel” is. Carbon steel has
been used successfully in hydrofluoric-acid environments for decades. At temperatures below
150℉, carbon-steel piping is highly resistive to corrosion from the hydrofluoric acid running
through it because the chemical reaction between carbon steel and hydrofluoric acid results in the
formation of an iron-fluoride scale which protects piping from corrosion. See Trial Tr. 99:3–19
(Apr. 11, 2025) (Carnahan).
2. Changing methods for steel production affects the resiliency of piping systems
used in hydrofluoric-acid environments.
But the introduction of other elements into carbon steel—whether purposefully or
unintentionally through the manufacturing method—will alter the behavior and performance of
carbon steel. See Stipulated Ex. 157 (“In addition to the predominant effects of carbon content
and microstructure, the properties of plain carbon steels may be modified by the effects of
residual elements other than the carbon, manganese, silicon, phosphorus and sulphur which are
always present.” (emphasis added)). So fittings composed of carbon steel plus other elements in
significant quantities will perform in some environments, but will not endure in an environment
using highly hazardous catalysts such as hydrofluoric acid because those alloys cannot chemically
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 10 of
47

11
build the protective iron-fluoride scale needed to protect against corrosion. See Trial Tr. 99:20–
23 (Apr. 11, 2025) (Carnahan) (“However, if there’s more than a certain amount of certain
elements, such as nickel and copper, then the steel is unable to form a protective iron-fluoride
scale, and it’s susceptible to general corrosion under conditions where non-copper, non-nickel-
containing steels would be fine.”).
Manufacturers have produced steel in the United States in several ways over the years:
Figure 20. US steel production by steelmaking process, 1950 through 2015.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 11 of
47

12
See Joint Ex. 181, at 19 (Figure 20), [ECF Doc. 244].8 In 1950, approximately 90% of U.S. steel
was manufactured using the “open-hearth” process whereby a mixture of approximately 55–60%
carbon-rich molten “pig iron” (an intermediate product created by smelting iron ore in a blast
furnace) and 35–40% scrap metal is heated by combustion gas in an open-refractory hearth. See
Trial Tr. 137:20–137:2 (Apr. 10, 2025) (Stevick); Trial Tr. 109:4–14 & 110:7–111:4 (Apr. 11,
2025) (Carnahan); Joint Ex. 181, at 17–22, Table 2, Table 3 & Figure 20. The open-hearth process
is a reliable, but slow, process known for producing high-purity steel. See Trial Tr. 109:4–14 &
110:7–111:4 (Apr. 11, 2025) (Carnahan). But by 1970, the percentage of steel produced in the
United States using that method had decreased to approximately 37%. See Trial Tr. 110:7–111:4
(Apr. 11, 2025) (Carnahan); Joint Ex. 181, at 19–21, Table 2 & Figure 20. The use of the time-
consuming open-hearth method for steel production continued to decline until 1993, when
manufacturers ceased using that method entirely. See Joint Ex. 181, at 19–21, Table 2 & Figure
20.
Starting in 1955, steel manufacturers produced steel using the “basic-oxygen” process,
whereby a mixture of approximately 70–75% pig iron and 25–30% scrap metal is made into high-
purity steel using an oxygen lance. See Trial Tr. 111:5–9 (Apr. 11, 2025) (Carnahan); Joint Ex.
181, at 19–21, Table 2 & Figure 20. By 1970, manufacturers using this quicker method produced
approximately half of the steel manufactured in the United States. See Joint Ex. 181, at 19–21,
Table 2 & Figure 20. Steel manufacturers used the basic-oxygen process to produce approximately
8 Figure 20 and Table 3 from Mr. Carnahan’s expert report are reproduced herein. Figure 20
represents a summary of the steelmaking processes used in the United States between 1950 and 2015 and
Table 3 reveals historical scrap usage in various steelmaking processes. The information summarized in
Figure 20 and Table 3 is based on data obtained by Mr. Carnahan from the Bureau of Mines Minerals
Yearbook for Iron and Steel, the United States Geological Survey Mineral Commodity Summaries for Iron
and Steel, and the tenth edition of The Making, Shaping and Treating of Steel issued by United States Steel
in 1985. See Joint Ex. 181, at 19–22.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 12 of
47

13
60% of this country’s steel between 1975 and 1995; after that, however, use of the basic-oxygen
process declined, giving way to use of electric furnaces to manufacture steel. See Joint Ex. 181,
at 19–21, Table 2 & Figure 20.
Through 1965, use of electric furnaces to manufacture U.S. steel produced less than 10%
of this country’s steel, but their use significantly increased around 1975 and surpassed use of the
basic-oxygen process in 2002, with 50% of U.S. steel being manufactured at that time by electric
furnaces. See Trial Tr. 111:10–16 (Apr. 11, 2025) (Carnahan); Joint Ex. 181, at 17–22, Table 2 &
Figure 20. By 2015, that percentage had climbed to approximately 63%. See Joint Ex. 181, at 17–
22, Table 2 & Figure 20. The major difference between use of electric furnaces and all other
methods for steelmaking is the fact that electric furnace steel is made from almost 100% scrap
metal:
Table 3. Historical Scrap Usage by Steelmaking Process
Type of
Furnace
1960 1970 1980
Scrap Pig Iron Scrap Pig Iron Scrap Pig Iron
Open-Hearth 43.0 57.0 41.4 58.6 43.4 53.6
Basic Oxygen 26.9 73.1 30.1 69.9 27.9 72.1
Electric 96.4 3.6 98.1 1.9 97.9 2.1
Bessemer 12.1 87.9
Joint Ex. 181, at 22 (Table 3) (reflecting percentages of materials used in steelmaking process);
Trial Tr. 114:9–11 (Apr. 11, 2025) (Carnahan). Scrap metal is known to be contaminated with
residual elements including nickel and copper. See Trial Tr. 58:11–14 (Apr. 11, 2025) (Reynolds);
Trial Tr. 111:10–16 (Apr. 11, 2025) (Carnahan).9
9 And not all scrap metal is the same. “Home scrap” is scrap that is left over from the steelmaking
process itself—that is, generated at the steel plant and remelted to avoid waste. See Trial Tr. 114:12–115:20
(Apr. 11, 2025) (Carnahan). “Purchase scrap” is scrap bought from various sources, such as machine shops
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 13 of
47

14
Relevant here, between 1969 and 1972, manufacturers produced approximately 83% of the
country’s steel using either the open-hearth process or the basic-oxygen process, each of which
produces high-purity steel. See Joint Ex. 181, at 17–22 & Table 2. Steelmakers forged the
remaining 17% of the country’s steel during those four years using electric furnaces. See id.
B. Construction of Unit 433 at the Girard Point Refinery
In the early 1970s, Gulf Oil Company (“Gulf Oil”) contracted with the Foster Wheeler
Corporation (“FWC”) for the construction of HF Alkylation Unit No. 433 (“Unit 433”) at the
Girard Point Refinery, part of an oil-refining complex owned by Gulf Oil in Philadelphia,
Pennsylvania. See Trial Tr. Day 2, 8:11–10:10 (Apr. 8, 2025) (Rutkowski); Joint Pretrial Order,
§ G, ¶¶ 27, 36 & 46.10 The contract between Gulf Oil and FWC delegated general contractor
duties to FWC for process design, mechanical design, purchasing, expediting, inspection, field
supervision, construction, and startup observation for Unit 433, to be performed per accepted
engineering standards. See Joint Pretrial Order, § G, ¶ 47; Joint Ex. 14 [ECF Doc. 241]. FWC
specified both “ASTM A234 WPB” elbow joints as well as YOLOY brand-named alloy steel
elbow joints for use in the Girard Point Refinery, depending on the application (i.e., process
conditions and the location at which a particular elbow joint would be incorporated into a specific
piping system). See Joint Pretrial Order, § G, ¶ 38.11
or junkyards, and recycled to make steel. See id. The existence of residual elements in scrap is not in
question, only the quantity.
10 Facts to which the parties stipulate for trial purposes are contained in the Joint Pretrial Order dated
April 4, 2025. [ECF Doc. 254].
11 YOLOY is the brand name of an alloy manufactured and marketed by B&W, composed of carbon
steel and intentionally added quantities of copper and nickel. See Trial Tr. 211:14–213:15 (Apr. 7, 2025)
(Rutkowski); Trial Tr. 211:7–212:15; 254:20–256:11 (Apr. 10, 2025) (Stevick); Stipulated Ex. 61, [ECF
Docs. 241 & 251].
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 14 of
47

15
During the construction of Unit 433, FWC sourced materials, including piping and elbow
joints (a/k/a “fittings”) from a variety of vendors, subcontractors, and fabricators, including B&W.
See Joint Pretrial Order, § G, ¶¶ 36–39 & 46–47. On August 22, 1972, FWC issued specifications
for materials to be used for the piping system for the hydrofluoric-acid alkylation Unit 433. See
Stipulated Ex. 125, [ECF Docs. 243 & 251]. FWC’s specification for “Piping Materials” generally
called for “Carbon Steel, Monel Trim Valves,” and specifically required fittings with diameters
sized between 1½ inches to 24 inches to comply with “ASTM A234, Grade WPB, weight to match
pipe.” See Stipulated Ex. 125; Joint Pretrial Order, § G, ¶ 40–41. Compliance with an “ASTM
A234, Grade WPB” specification would require vendors to supply elbow joints comprised of
carbon steel, grade B—meaning the chemical make-up of elbow joints would be limited to the
percentages of elements found in ASTM A106 (shown in Table I above). See Joint Exs. 171B &
171S, § 4.1 & Table I; Joint Pretrial Order, § G, ¶ 40–41; Trial Tr. 108:13–24 (Apr. 11, 2025)
(Carnahan).12
In July 1972, FWC contracted with Southwest Fabricating & Welding Co. to fabricate a
pipe spool for installation in the N-01 Circuit of Unit 433. See Stipulated Ex. 18, [ECF Docs. 241
12 Of note: Also on August 22, 1972, FWC issued specifications for materials to be used for the piping
system installed in a steam condensate unit of the Girard Point Refinery. See Stipulated Ex. 140-1, [ECF
Doc. 244 & 251]. Unlike the specifications for hydrofluoric-acid alkylation Unit 433, FWC’s specifications
for the steam-condensate unit generally called for “Yoloy Pipe & Fittings, Carbon Steel Valves,” and
specifically required fittings with diameters sized between ½-inch to 16 inches to be made of “Yoloy, weight
to match pipe.” See id. The FWC contracts contain no language allowing unilateral material substitutions
with or without notice to the contractor.
Dr. Stevick suggested that material substitutions by suppliers are commonplace in the refining
industry either for lack of availability of the requested material or in instances where the supplier believes
that the substitution constitutes a material upgrade. See Trial Tr. 126:8–129:4; 137:18; 142:10–20 (Apr. 10,
2025) (Stevick). Dr. Stevick further asserted that a Yoloy substitute supplied for a contract calling for A234
Grade B component parts to be installed for use in a hydrofluoric-acid environment would have satisfied
that contract in 1972. See Trial Tr. 238:18–249:9 (Apr. 10, 2025). The Court found Dr. Stevick’s testimony
on cross-examination to be evasive and extremely speculative; regardless, that testimony is unhelpful to
resolving the matter before this Court.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 15 of
47

16
& 251]. The pipe spool was comprised of four parts: two 8-inch, 90-degree standard-weight long-
radius elbows and two 23’3” seamless pipes. See Trial Tr. 99:24–100:7 (Apr. 11, 2025)
(Carnahan); Stipulated Exs. 18 & 51, [ECF Docs. 241 & 251]. The contract specified that the
elbows (“T-1 Elbow” and “T-2 Elbow”) were to be made of “A234 B” material, or carbon steel,
grade B. See Stipulated Ex. 18; Joint Exs. 171B & 171S, § 4.1 & Table I. Likewise, the contract
specified that the seamless pipes (“T-3 Pipe” and “T-4 Pipe”) would be made of “A106 . . . GR B”
material, or carbon steel, grade B. See Stipulated Ex. 18; Joint Exs. 171B & 171S, § 4.1 & Table
I. At the time of installation in the N-01 Circuit of Unit 433, no cause existed to believe that the
T-1 Elbow was made of anything other than A234 Grade B carbon steel.
C. Ownership of the Girard Point Refinery (1970 to Date)
In June 1985, Gulf Oil merged with Chevron Corporation and, in 1994, Chevron sold the
GP Refinery to Sunoco, Inc. (“Sunoco”). See Joint Pretrial Order § G, ¶¶ 28 & 29. Sunoco
remained the sole owner of the GP Refinery until June 2012, when it formed Philadelphia
Solutions, LLC (“PES LLC”) with a private equity fund and a co-investment fund and contributed
the GP Refinery to PES LLC. See Joint Pretrial Order § G, ¶ 30.13 PES LLC operated the GP
Refinery through its wholly owned subsidiary, PESRM, formed for that purpose. See id. On
August 14, 2012, Sunoco (n/k/a Sunoco (R&M), LLC), the Commonwealth of Pennsylvania
Department of Environmental Protection, and PESRM entered into a Consent Order and
Agreement that transferred the GP Refinery to PESRM pursuant to a Special Warranty Deed dated
September 7, 2012. See Joint Pretrial Order § G, ¶ 31. A number of Sunoco employees became
PESRM employees when Sunoco contributed the Girard Point Refinery to the joint venture in
13 Initially, Sunoco held a 49% interest in PES LLC. See Joint Pretrial Order § G, ¶ 30.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 16 of
47

17
2012. See Joint Pretrial Order § G, ¶ 45. Sunoco’s on-site inspection and monitoring records were
transferred to PESRM in or about 2012. See id.
D. Best Practices in Inspection and Maintenance of Existing Piping Systems in
Hydrofluoric-Acid Environments
Operators maintaining dynamic systems like hydrofluoric-acid alkylation units must
adhere to applicable safety regulations, such as the Occupational Health and Safety
Administration’s Process Safety Management (“OSHA PSM”) standards and the Environmental
Protection Agency’s Risk Management Program (“EPA RMP”) norms promulgated in the 1990s.
See Trial Tr. 7:27–32; 14:5–24; 15:26–16:3; 17:10–18:24 (Apr. 8, 2025) (Rutkowski); Trial Tr.
323:5–332:13 (April 10, 2025) (Arendt). Both the OSHA PSM and the EPA RMP standards
address fourteen elements or focus areas, one being “mechanical integrity.” Trial Tr. 332:14–
334:10 (April 10, 2025) (Arendt). Because of the complexity, diversity, and highly technical
nature of this specialized field, imposing “one-size-fits-all” rules on the industry is not effective
and will not contribute to achieving the industry’s “no accidents” goal. See Trial Tr. 325:14–
326:17 (Apr. 10, 2025) (Arendt). This is especially true regarding mechanical-integrity standards.
See Trial Tr. 332:24–333:3 (Apr. 10, 2025) (Arendt). Thus, one finds that the mechanical-integrity
provisions in OSHA PSM and EPA RMP standards rely heavily on “Recognized and Generally
Accepted Good Engineering Practices” or “RAGAGEP,” particularly as they relate to inspection
and testing of existing piping systems. See Trial Tr. 336:25–337:16; 366:20–367:4 (Apr. 10, 2025)
(Arendt). As explained by Steve Arendt:
In the early part of the rulemaking in ’88, ’89, OSHA had a phrase that they
used that was—essentially said ‘comply with codes and standards,’ and that was
the phrase they used; and in discussions with all of the stakeholders, they realized
that that wouldn’t make sense because, if you included that [requirement], every
time a code and standard got revised, you would have to revise their rule. And so
they considered and accepted the language “recognized and generally accepted
engineering practices” and talked about a framework for what source material could
be included as RAGAGEP.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 17 of
47

18
And so like a lot of things, OSHA might put out terminology like that, but
not necessarily give a lot of guidance immediately about what it meant and how to
implement it, and so it was left up to industry or others to decide what it meant and
how to implement it over time based on experience.
. . . .
So, again, it took time for new concepts to roll out for people to figure out
whether they were valuable in a technical sense and for them to do it. So over time
people would trade information in conferences and papers and through experiences
and then you would judge . . . whether—some of the source material was judged to
be not only recognized, but it was also generally accepted by the constituent
facilities that would—that might judge it to be a part of their RAGAREP.
. . . .
So the term recognize[d] or generally accepted good . . . engineering
practices . . . . “[G]ood” meant not the absolute edge, the leading-edge idea that
somebody just thought . . ., but it was “good” almost in the concept of what was
“good enough,” and that was subject to subjectivity in the eye of the beholder, but
it had to be “good.”
So you combine all of those words, it gives you . . . a framework for trying
to think about what . . . source material . . . would be relevant to your facility and
your industry, what you could choose to be a RAGAREP.
Trial Tr. 337:25–342:8 (Apr. 10, 2025) (Arendt).
Alkylation unit operators routinely turn to source material generated by trade organizations
such as the American Petroleum Institute (“API”) or the organization formerly known as the
National Association of Corrosion Engineers (“NACE”) to determine the consensus on
RAGAGEP and develop and implement best practices in their own facilities. See Trial Tr. 52:9–
16 (Apr. 8, 2025) (Rutkowski); Trial Tr. 342:9–344:21 (Apr. 10, 2025) (Arendt).14 The
RAGAGEP for inspection of refinery piping systems relies primarily on API Recommended
Practice 570. See Trial Tr. 48:12–50:20 (Apr. 11, 2025) (Reynolds).
14 Organized in the early 1940s, the National Association of Corrosion Engineers is a group of
engineers and other professionals who collaborate and develop corrosion prevention and control standards.
It exists now as the Association for Materials Protection and Performance.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 18 of
47

19
1. The American Petroleum Institutes’ recommendations on piping inspections in
hydrofluoric-acid environments
The API is a long-standing national trade organization in the energy sector that, among
other things, has set industry standards and recommended practices to promote safe operations;
relevant here, the API has issued standards, recommendations, and certifications for piping
inspection, safe operation of hydrofluoric-acid alkylation units, and material verification for alloy
piping systems. See Trial Tr. 47:13–25 (Apr. 7, 2025) (Rutkowski); Stipulated Ex. 69, [ECF Docs.
251 & 252]; Joint Exs. 153 & 176, [ECF Doc. 256]. In January 1990, the API promulgated
Recommended Practice 570 addressing “Management of Process Hazards,” followed shortly by a
background paper entitled “The Use of Hydrofluoric Acid in the Petroleum Refining Alkylation
Process.” See Joint Ex. 153A. A second edition of API 570 entitled “Piping Inspection Code”
and specifically addressing “Inspection, Repair, Alteration, and Rerating of In-service Piping
Systems” was issued in 1998. See Stipulated Ex. 69.
API 570 acknowledged that “[d]ifferent types of inspection and surveillance are
appropriate depending on the circumstances and the piping system,” and recommended thickness-
measurement inspection, external visual inspection, vibrating-piping and line-movement
surveillance, and supplemental inspections, scheduled as appropriate, to include ultrasonics and/or
radiography for detecting localized corrosion of piping. Id. § 5.4; see also Trial Tr. 12:23–13:15
(Reynolds) (discussing “nondestructive examination” methods to monitor piping systems for
corrosion). Commonly used, thickness-measurement inspections are performed by facility
inspectors “to determine the internal condition and remaining thickness of the piping components.”
Stipulated Ex. 69, § 5.4.2.
To facilitate thickness-measurement inspections, API 570 recommended establishing
thickness-measurement locations or “TMLs” which are “specific areas along the piping circuit
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 19 of
47

20
where inspections are to be made,” to be selected after “consider[ing] the potential for localized
corrosion and service-specific corrosion.” Id. § 5.5.1.15 As API 570 explains:
The minimum thickness at each TML can be located by ultrasonic scanning
or radiography. Electromagnetic techniques also can be used to identify thin areas
that may then be measured by ultrasonics or radiography. When accomplished with
ultrasonics, scanning consists of taking several thickness measurements at the TML
searching for localized thinning. The thinnest reading or an average of several
measurement readings taken within the area of a test point shall be recorded and
used to calculate corrosion rates, remaining lift, and the next inspection date. . . .
Id. § 5.5.2. “The frequency and extent of inspection on piping circuits depend on the forms of
degradation that can affect the piping and consequence of a piping failure.” Id. § 6.1. Thus,
“[p]iping circuits with high potential consequences if failure should occur and those subject to
higher corrosion rates or localized corrosion will normally have more TMLs and be monitored
more frequently.” Id. § 5.5.2. API 570 required intervals between piping inspections to be
established and maintained in light of:
a. Corrosion rate and remaining life calculations.
b. Piping service classification.
c. Applicable jurisdictional requirements.
d. Judgment of the inspector, the piping engineer, the piping engineer
supervisor, or a corrosion specialist, based on operating conditions, previous
inspection history, current inspection results, and conditions that may warrant
supplemental inspections . . . .
Id. § 6.3.
Implementing an inspection program using representative samples from various locations
is the “primary way” to determine the likely corrosion rate of a piping circuit. Trial Tr. 14:3–16
(Apr. 11, 2025) (Reynolds). As explained by Mr. Reynolds:
15 TMLs are also referred to as “conditioned monitoring locations” or “CMLs.” Trial Tr. 54:18–55:20
(Apr. 7, 2025) (Rutkowski); Trial Tr. 13:23–14:2 (Apr. 11, 2025) (Reynolds).
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 20 of
47

21
Once we know what a system is and it’s all one type of material construction, then
we typically put [T]MLs in various locations, sometimes on piping straight runs,
sometimes on fittings, sometimes on what we call Ts. There are lots of different
components in a piping system, and so we will spread our [T]MLs out over the
various components in order to monitor the system.
. . . .
[I]n order to use [T]MLs properly, we determine, first of all, what the material of
construction is for the entire system and break the system down into various
segments and put our [T]MLs in a . . . place that we think will monitor the corrosion
. . . in each segment of piping or each pressure vessel.
[T]he materials of construction are very important . . . . like it is codified in
API 570, we disperse [T]MLs over the system. [B]ut we don’t put a [T]ML on
every inch of the pipe, every fitting, every T. [N]obody does that. [W]e get a very
good representative sample . . . to know what the general corrosion rate is for the
entire system.
Trial Tr. 14:6–15:3 (Apr. 11, 2025) (Reynolds).
2. The 2003 NACE Report highlighted concerns regarding residual elements
contained in hydrofluoric acid alkylation units’ piping systems.
In 1999, a group of eight petroleum companies, including Sunoco, Conoco Inc., and
Phillips Petroleum Company, organized a group of engineers and funded a project labeled as a
“Petroleum Environmental Research Forum” or “PERF” to research and develop (i) test and
corrosion rate measurement procedures for evaluating material in hydrofluoric-acid environments
as well as (ii) a carbon-steel materials specification with respect to the levels of residual elements
and carbon in steels for hydrofluoric-alkylation equipment. See Joint Ex. 165, at 1, [ECF Doc.
255]; see also Trial Tr. 78:10–80:23 (Apr. 7, 2025) (Rutkowski). NACE published the PERF’s
findings in 2003 (the “2003 NACE Report”). See Joint Ex. 165, at 1.16 The PERF identified the
issue facing the industry in the late 1990s/early 2000s:
16 The report includes the caveat that “[t]he material presented and the views expressed in this paper
are solely those of the author(s) and not necessarily endorsed by the [NACE] Association.” See Joint Ex.
165.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 21 of
47

22
Operation of hydrofluoric (HF) acid alkylation units using primarily carbon
steel construction material has been the norm for over 60 years. There have been
few problems associated with the use of this material for many years. There have
been problems reported within the last 10 years where a non-uniform corrosion
phenomenon occurs leading to plant incidents. Residual elements (RE), Cr, Ni and
Cu in carbon steel were implicated as a potential cause for this problem. There
were inconsistencies though claimed by others or within differing parts of the plant
about this RE effect. Galvanic effects were reported that might negate the possible
beneficial use of low RE materials.
Id. at 1 (emphasis added).17 The 2003 NACE Report’s conclusions identified two causes of non-
uniform corrosion in hydrofluoric-acid environments: (1) the chemical composition of the
hydrofluoric-acid solution flowing through piping systems and (2) the chemical composition of
the pipes themselves. See id. at 9–10.18 Regarding the second cause, the corrosive effect of
residual elements in steel pipes in hydrofluoric-acid environments, the PERF concluded:
17 One of the engineers on the PERF from the Phillips Petroleum Company, Hisham Hashim,
presented research and conclusions contained in an internal white paper entitled “Effect of Residual Copper,
Nickel, and Chromium on the Corrosion Resistance of Carbon Steel in Hydrofluoric Acid Alkylation
Service” at the NACE Annual Conference and Corrosion Show in 1993 (the “1993 White Paper”). See
Stipulated Ex. 65, [ECF Docs. 241 & 251]. The 1993 White Paper outlined the authors’ findings based on
field samples and supporting laboratory test data and served as a precursor to the 2003 PERF project.
Hashim concluded in the 1993 White Paper that:
1. Residual content of chromium, nickel, and copper has a detrimental effect on the
corrosion resistance of ASTM carbon steel grades in HF.
2. The residual elements do not promote the formation of protective adherent iron fluoride
on the surface.
3. Carbon steel grades meeting the specified ASTM materials specifications may contain
residuals of sufficient quantities to decrease the corrosion resistance of the steel in HF.
4. Keeping the total content of chromium + nickel + copper to less than 0.2%, improves
the corrosion resistance to HF.
Id. at 7. Although cited in the 2003 NACE Report, no evidence before the Court suggests that the 1993
White Paper was widely circulated among industry participants at the time it was authored.
18 As to the first cause, the PERF concluded:
• Corrosion problems in areas of HF alkylation units handing strong acid are
considered to be due to:
i. The presence of impurities other than water in the concentrated HF, and/or
(not significantly tested in this program.)
ii. The presence of water at locally high concentrations.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 22 of
47

23
• Combinations of copper and nickel have the most detrimental effect on
corrosion of steels in “concentrated” HF. Carbon appears to be beneficial,
except in combination with high nickel content. Chromium appears to be
neutral or even beneficial at higher carbon levels, but may become slightly
detrimental as the carbon concentration is reduced.
• Overall, the results support a maximum residual element (RE) criterion
(where the RE content is based on the wt % summation of nickel, chromium
and copper content), although a reduction from the industry guideline value
of 0.2% to 0.15% would be beneficial if this is practical in terms of materials
supply.
• There is a strong effect of carbon, particularly in low RE materials.
This could explain the greater incidence of failures in recent years due
to use of modern low carbon steels. It could also explain some anomalous
results in relation to the 0.2% alloying criterion. From this work a carbon
concentration of 0.18% or greater is recommended.
• From the above conclusions it is considered that if the minimum carbon
recommendation is met for a given material, then chromium can be
excluded from the maximum RE requirement. However, if the minimum
carbon recommendation is not met then chromium should be included in
calculating the total RE value.
• For base metals the optimum specification would be C >0.18 wt%
and Cu + Ni + Cr < 0.15 wt%.
• For weld metals the specification should be (where C levels are
lower) Cu + Ni + Cr < 0.15 wt%
Id. at 9 (emphasis added).
• Consideration of the HF solution chemistry indicates that under significant
pressure drop conditions, concentrated HF is likely to evaporate to a liquid phase
concentration of 67% and hence scenario (ii) above is viable.
• Tests in 60% HF at 71℃ [158℉] has been shown to reflect the residual element
effects observed in service.
. . . .
• Studies on coupled materials and weldments have shown that in 60% HF, corrosion
is dominated by diffusion effects through the fluoride film. Hence, galvanic effects
are expected to be less significant in this and more concentrated HF environments.
Joint Ex. 165, at 9.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 23 of
47

24
The concerns contained in the 2003 NACE Report regarding the chemical composition of
piping systems installed post-1990 permeated the industry. See Trial Tr. 82:8–13; 102:13–105:17
(Apr. 7, 2025) (Rutkowski). Even as early as May 1997, Anthony Rutkowski, corrosion engineer
and piping inspector in Unit 433, notified his superiors at Sunoco of the investigation results from
an incident that occurred in an alkylation unit at a competitor’s refinery, “suggest[ing] the problem
is related to the total chrome, nickel and copper content” of failed piping in that facility. Stipulated
Ex. 33, at 12–19, [ECF Doc. 241 & 251]. Rutkowski wrote in 1997:
. . . . Although this theory is not conclusive, it does appear to make it worth the
effort to special order carbon steel equipment in HF service.
I have also just learned that the Citgo, Corpus Christi Refinery had the same line
fail about two weeks ago. They are still in the process of the investigation and
could not provide any details yet. They did tell me they have revised their pipe
specification for all HF service to limit the total CrNiCu to <.2% in carbon steel
material.
I think a little more research should be done before we do a wholesale revision, but
it is definitely the thing to do in the Feed system.
Id. at 12.
In November 2003, ConocoPhillips, which designed Unit 433, sent updated “Process
Design Specifications for HF Alkylation” to its licensee, Sunoco. See Stipulated Ex. 24, at 7, [ECF
Doc. 241 & 251]; Trial Tr. 56:9–57:8 (Apr. 11, 2025) (Reynolds). Relevant here, those process-
design specifications lowered the recommended maximum percentages of residual elements
copper and nickel in carbon steel used in piping systems to 0.15%. See Stipulated Ex. 24, at 3 &
9. ConocoPhillips intended the updated process design specifications to be “of benefit to both
those constructing new Alkylation units and those making repairs on existing Phillips HF
Alkylation units,” with the caveat:
As with earlier revisions to these specifications, the changes made should not
suggest that the specifications under which older HF Alkylation units were
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 24 of
47

25
originally constructed were wrong. The revisions should simply serve to improve
the quality of construction and repairs.
Id. at 7.
3. The scope and frequency of piping inspections in the N-01 Circuit complied
with RAGAGEP and API recommendations.
Despite raising awareness regarding the negative impact of residual elements on the
integrity and performance of piping systems installed in hydrofluoric-acid alkylation units, the
2003 NACE Report made no recommendations regarding the frequency of inspections or
replacement of long-existing piping systems. The advice offered in the 2003 NACE Report was
“wait and see”:
There is still uncertainty as to the possible impact of contaminants found in
operating plants that may impact the corrosivity of the [hydrofluoric acid]. This
may be a wild card that may also impact the response of carbon steel in some plants
while not in others. A proposal for further work in this area is being offered for a
second phase study in better understanding HF acid corrosion to carbon steel.
See Joint Ex. 165, at 10 (emphasis added).
The API also updated its Recommended Practice 571 in 1999, expanding on the industry’s
residual-element concerns specific to hydrofluoric-acid alkylation. See Joint Ex. 153A. According
to the 1999 API 571, “[t]he principal materials of construction for HF alkylation units are carbon
steel and the nickel-copper Alloy 400 (e.g., Monel 400)” while “[o]ther materials, such as 70-30
copper-nickel and nickel-base Alloys C-276 and B-2 (e.g., Hastelloy C-276 and B-2), have been
used in selected applications.” Id. § 3.2. Describing the strength of installing carbon-steel piping
in hydrofluoric-acid alkylation units, the 1999 API 571 stated:
Corrosion of carbon steel by HF is a function of water content, temperature,
velocity, and contaminants. Carbon steel has demonstrated satisfactory resistance
to concentrated HF up to approximately 150℉. This temperature should not be
considered as a limit. Actual experience in alkylation units varies, some indicating
unsuitable performance at lower temperatures and some indicating suitable
performance up to 180–200℉, depending on the specific exposure conditions.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 25 of
47

26
Carbon steel relies to a large extent on the presence of a protective iron fluoride
film for its HF corrosion resistance.
Id. § 3.2.1. The 1999 API 571 cautioned however:
Loss of this protective [iron fluoride] film can result in accelerated corrosion rates.
Welding slag is rapidly attacked by HF. It has also been reported that certain
residual elements (Cr, Ni, Cu) in carbon steel may contribute to accelerated HF
corrosion (See NACE Publication 5A171 for further details).
Id. Like the 2003 NACE Report, the 1999 API 571 did not make recommendations regarding the
scope or frequency of inspections of long-existing piping systems, but deferred to API 570 for best
practices regarding inspections and inspection intervals for piping and welded components in
hydrofluoric-acid units. See id. § 3.4.3; see also supra Part I.D.1 (discussing API 570).19 Later
updates to API 571 also incorporated API 570 for inspection of commissioned hydrofluoric-acid
unit equipment. See Joint Exs. 153B, § 3.4.3 (2007 API 571) & 153C, § 3.4.3 (2013 API 571),
[ECF Doc. 253].
Not until API 571’s 2021 update did the API make a specific recommendation for operators
to inspect 100% of all individual component parts installed in hydrofluoric-acid environments at
least once:
Special emphasis inspection programs to evaluate the condition of all individual
components and welds in piping circuits have been conducted by several owner-
operators. Most of these programs have identified locations with significant
corrosion rate variations and localized thinning of components, welds, and weld
HAZs requiring repairs or replacement. Refer to 6.2.2.1 for additional information
regarding considerations for [residual elements] in carbon steel.
A special emphasis inspection program shall be developed and implemented
at least once to inspect all individual carbon steel piping components and welds
to identify areas of accelerated corrosion. Aspects of the program shall include:
a) the program shall be completed in all HF corrosion zones identified in
Annex G, [and]
b) the program shall be prioritized by corrosion zone with phase change HF
and dilute HF in water corrosion zones given priority based on known corrosion
19 No evidence of any updates to API 570 after 1998 is before the Court. See Stipulated Ex. 69.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 26 of
47

27
potential. After the initial inspection of all carbon steel components, the results
should be used to adjust the ongoing inspection and repair plans and evaluate the
frequency and/or need to inspect each component.
This special emphasis inspection program shall determine the wall thickness of
individual components and welds throughout the unit. The program typically
consists of:
1) identification of all the welds (and thus piping components);
2) the use of the radiographic and ultrasonic techniques to determine the
thickness of the components on each side of the weld as well as the thickness at the
weld.
After the initial inspection, the [T]MLs for each piping circuit should include
[T]MLs placed on components that have lower wall thicknesses and/or higher
corrosion rates. Successive inspection programs can be implemented to track the
findings, to address the impact of operational changes, or to address industry
learnings.
Some owner-operators have included [positive material identification] for [residual
elements] as part of their special emphasis inspection program.
Joint Ex. 153D, § 6.4.2.3.3, [ECF Doc. 253] (emphasis added). The impetus for the addition to
the 2021 API 571 inspection recommendation was based, in part, on the June 2019 failure incident
at the Girard Point Refinery. Mr. Kemeny, who played an integral role in the investigation of the
explosion in Unit 433 and was very involved in the discussion group charged with updating the
2021 API 571, explained:
In fact, we, as part of the investigation, we . . . found out what occurred with having
a fitting in the line that we did not expect, [and] we actually sent out an industry
alert that told the industry of our lessons learned and our experience and that . . .
people need to do some sort of retro examination of this carbon steel components
in HF service.
. . . .
[O]ur finding, as the investigation lead of that incident, was we found a fitting that
unfortunately we did not inspect . . . . It was not part of our condition monitoring
locations, but it ended up being of a different metallurgy than the other carbon steel
components in that line. And instead of having a very low corrosion rate over 40
years, it was significantly higher than the other existing components, and we
believe that that was the root cause for that failure.
Trial Tr. 159:21–160:16 (Apr. 8, 2025) (Kemeny).
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 27 of
47

28
From the start of Unit 433’s operations, in accordance with RAGAGEP, Chevron and
Sunoco developed and implemented piping-inspection procedures that included a formula for
assigning TMLs throughout Unit 433 based on factors such as process flow and materials of
construction. See Trial Tr. 29:25–30:20 (Apr. 8, 2025) (Rutkowski); Trial Tr. 161:9–162:19 (Apr.
8, 2025) (Kemeny). As to inspection of the N-01 Circuit specifically, Mr. Kemeny explained:
The refinery followed practices that were existent prior to [the] 2021 change
to the [API] 751 to place condition monitoring locations across a circuit through
some methodology. So they followed a methodology.
The inspection group was the responsible party for that, and the
methodology included bleeder locations, elbows, tees, but it certainly didn’t require
every single component. But there was a formula that they used to come up with
the number of components that would be tested. And I, after going through as the
investigation team leader, and they showed us their methodology and informed us,
and I would admit that I did not know this prior [to] being the team leader, that they
actually used a very conservative approach and more than doubled the . . . expected
number of [T]MLs for that location.
Trial Tr. 161:13–162:5 (Apr. 8, 2025) (Kemeny). The inspection procedures implemented by the
operators of the Girard Point Refinery established approximately 55 TMLs on the N-01 Circuit at
the time of its construction and increased that number over the years to 126 TMLs, “considerably
above what was needed for a circuit that was, in general, corroding at very low rates.” Trial Tr.
51:6–52:9 (Apr. 11, 2025) (Reynolds); see also Trial Tr. 54:2–10 (Apr. 11, 2025) (Reynolds)
(“[The refinery’s [T]ML program for inspection of the N-01 Circuit complied with RAGAGEP
and] it actually exceeded the nominal amount of [T]MLs necessary because . . . they were
concerned about what they were hearing about corrosion rates, and so they were increasing the
number of [T]MLs, and even though they increased the number of [T]MLs—they more than
doubled them—they did not find any difference in the corrosion rates being recorded.”); Joint Exs.
131A & 131B, [ECF Doc. 287].
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 28 of
47

29
The T-1 Elbow never served as a TML, but the T-2 Elbow welded to it did. See Trial Tr.
147:9–148:2 (Apr. 8, 2025) (Kemeny); Joint Ex. 131A; see also Trial Tr. 71:19–72:2 (Apr. 11,
2025) (Reynolds). As of 2001, Unit 433’s TML reports revealed no cause for concern regarding
thinning or corrosion in the piping system in the N-01 Circuit. See Trial Tr. 31:16–25 (Apr. 8,
2025) (Rutkowski); Trial Tr. 151:13–153:20 (Apr. 8, 2025) (Kemeny).
E. B&W’s Bankruptcy Case and Confirmed Plan of Reorganization
On February 22, 2000, B&W and three subsidiaries filed chapter 11 bankruptcy petitions
in this Court. See Joint Pretrial Order § G, ¶ 1; [No. 00-10992, ECF Doc. 1].20 At that time, B&W
and its subsidiaries were “leading suppliers of fossil fuel fired steam generating systems,
replacement commercial nuclear steam generators, environment equipment and related
components and services to its customers around the world.” [No. 00-10992, ECF Doc. 3147,
§ VII.A]. B&W and its affiliates sought chapter 11 bankruptcy relief primarily to deal with
asbestos-related personal-liability claims. [No. 00-10992, ECF Doc. 6913, § II.A (Summary
Disclosure Statement) & ECF Doc. 6849 (approving adequacy of disclosure statement)].
Sunoco received actual notice of B&W’s bankruptcy filing, as well as the January 15, 2003,
bar date for filing proofs of claim, and timely filed a proof of claim against the estate. See Joint
Pretrial Order § G, ¶¶ 2, 5–7; [No. 00-10992, ECF Doc. 474]. Sunoco’s proof of claim asserted a
non-asbestos-related claim pertaining to a facility unrelated to the Girard Point Refinery. See Joint
Pretrial Order § G, ¶¶ 7, 9 & 49. Gulf Oil and Chevron also received notice of B&W’s bankruptcy
20 The Court takes judicial notice of certain documents and orders filed in the main bankruptcy case.
See Banque de Paris et des Pays-Bas (Suisse) S.A. v. Arhens (In re Arhens), 120 B.R. 852, 854 (Bankr. S.D.
Tex. 1990) (citing Sec. & Exch. Comm’n v. First Fin. Grp. of Tex., 645 F.2d 429, 433 (5th Cir. 1981)). The
Court administered B&W’s bankruptcy case jointly with cases filed by subsidiaries Diamond Power
International, Inc. (No. 00-10993), Babcock & Wilcox Construction Co., Inc. (No. 00-10994), and
Americon, Inc. (No. 00-10995). [No. 00-10992, ECF Doc. 4].
.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 29 of
47

30
filing. See Joint Pretrial Order § G, ¶¶ 10–12; [No. 00-10992, ECF Docs. 5227 & 6462]. On May
15, 2002, this Court entered an Order denying B&W’s motion to extend the exclusive period within
which to gain acceptances to a plan of reorganization. [No. 00-10992, ECF Doc. 3173].
Ultimately, on December 22, 2005, after prolonged litigation and mediation, B&W and the other
jointly administered debtors, together with the official Asbestos Claimants’ Committee, the Court-
appointed Future Asbestos-Related Claimants’ Representative, and B&W’s parent company,
McDermott International, Inc., filed a Joint Plan of Reorganization as of September 28, 2005, as
Amended Through November 10, 2005 (with Technical Modifications Through December 22,
2005) (the “Joint Plan”). See Joint Pretrial Order § G, ¶ 14; [No. 00-10992, ECF Doc. 7003].
Sunoco had notice of the confirmation process and an opportunity to object to confirmation of the
Joint Plan and did not do so. See Joint Pretrial Order § G, ¶ 13. The District Court confirmed the
Joint Plan on January 17, 2006, and the Joint Plan became effective on February 22, 2006. See
Joint Pretrial Order § G, ¶¶ 15–16; [No. 00-10992, ECF Docs. 7053 & 7134].
The Joint Plan created the Asbestos PI Trust, funded with assets of B&W, its debtor-
affiliates, as well as certain non-debtor affiliates; under the Joint Plan, the Asbestos PI Trust served
as the sole recourse for payment of current and future asbestos-related claims against B&W. [No.
00-10992, ECF Doc. 6913, § II.B].21 All other non-asbestos-related claims, including Class 5
21 Three main sources funded the Asbestos PI Trust:
• Assignment of the rights to insurance proceeds shared by B&W and its non-debtor corporate
parent and affiliates, in the face amount of at least $1.15 billion;
• Transfer of the capital stock of B&W, which was valued at between $400 and $500 million;
and
• Additional contributions from certain of B&W’s parent companies, MI and MII, including 4.75
million shares of MII common stock with a minimum share price guaranty (valued at $123.1
million), $92 million aggregate principal amount of promissory notes, and certain tax benefits.
[No. 00-10992, ECF Doc. 6913, §§ II.B & III.B; ECF Doc. 7003, §§ 1.1.44, 1.1.57, 1.1.92, 3.2.6 & 7.2].
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 30 of
47

31
General Unsecured Claims, would be resolved directly by the Reorganized Debtors—in other
words, those claims would be paid pro rata as directed in the Joint Plan from proceeds generated
by Reorganized B&W’s continuing operations. [No. 00-10992, ECF Doc. 6913, §§ II.B & III.B;
ECF Doc. 7003, § 3.2].
With few exceptions not germane here, the Joint Plan discharges all prepetition claims
against the Reorganized B&W and imposes a permanent statutory injunction prohibiting creditors
from asserting those claims going forward:
Except as otherwise provided in this Plan, the rights afforded in this Plan and
the treatment of all Claims and Equity Interests herein shall be in exchange
for and in complete satisfaction, discharge, and release of all Claims and
Equity Interests of any nature whatsoever, including any interest accrued
thereon from and after the Petition Date, against the Debtors and the Debtors
in Possession, or their assets, properties, or interests in property. Except as
otherwise provided herein, on the Effective Date, all Claims against and
Equity Interests in the Debtors and the Debtors in Possession (including any
based on acts or omissions that constituted or may have constituted ordinary
or gross negligence or reckless, willful, or wanton misconduct of any of the
Debtors, or any conduct for which any of the Debtors may be deemed to have
strict liability under any applicable law) shall be satisfied, discharged, and
released in full. The Reorganized Debtors shall not be responsible for any
obligations of the Debtors or the Debtors in Possession except (1) those expressly
assumed by the Reorganized Debtors pursuant to this Plan and (2) those claims that
pass through this Plan unimpaired pursuant to Section 3.2.8 herein. All Entities
shall be precluded and forever barred from asserting against the Debtors, the
Reorganized Debtors, the Asbestos Protected Parties, Settling Asbestos
Insurance Entities, or their assets, properties, or interests in property any
other or further Claims or Demands based upon any act or omission,
transaction, or other activity, event, or occurrence of any kind or nature that
occurred prior to the Effective Date, whether or not the facts of or legal bases
therefor were known or existed prior to the Effective Date, except as expressly
provided in this Plan.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 31 of
47

32
[No. 00-10992, ECF Doc. 7003, § 11.2]; see also Joint Pretrial Order § G, ¶ 20.22 “Claim” is
defined in the confirmed Joint Plan as
a right to: (a) payment from any of the Debtors, whether or not such right is reduced
to judgment, liquidated, unliquidated, fixed, contingent, matured, unmatured,
disputed, undisputed, legal, equitable, secured, or unsecured; or (b) an equitable
remedy for breach of performance if such breach gives rise to a right to payment
from the Debtors, whether or not such right to an equitable remedy is reduced to
judgment, fixed, contingent, matured, unmatured, disputed, undisputed, secured,
or unsecured.
[No. 00-10092, ECF Doc. 7003, § 1.1.51 (emphasis added)]. “Contingent Claim” is defined in the
confirmed Joint Plan as
Any Claim, the liability for which attaches or is dependent upon the occurrence or
happening of, or is triggered by, an event, which event has not yet occurred,
happened, or been triggered, as of the date on which such Claim is sought to be
estimated or an objection to such Claim is filed, whether or not such event is within
the actual or presumed contemplation of the holder of such Claim and whether or
not a relationship between the holder of such Claim and the Debtor now or hereafter
exists or previously existed.
Id. § 1.1.56. “Demand” as defined in the confirmed Joint Plan means
a demand for payment, present or future, that (i) was not a Claim during the Chapter
11 Cases; (ii) arises out of the same or similar conduct or events that gave rise to
the Claims addressed by the Asbestos PI Channeling Injunction or the Asbestos PD
Channeling Injunction; and (iii) pursuant to this Plan is to be paid by the Asbestos
PI Trust (or the Reorganized Debtors in the case of Demands involving Asbestos
PD Claims). Notwithstanding the foregoing, nothing in this Plan concedes the
existence of Demands for Asbestos PD Claims as a matter of law.
Id. § 1.1.63.
F. The June 2019 Explosion at the Gerard Point Refinery and Investigation
B&W manufactured the T-1 Elbow that was installed as a component part of the N-01
Circuit in Unit 433 of the Girard Point Refinery in the 1970s. See Joint Pretrial Order § G, ¶ 39.
22 Section 3.2.8 of the Joint Plan dealt with a class of prepetition claims against B&W arising out of
the alleged presence of or exposure to nuclear contamination in two communities in Pennsylvania not
implicated in this dispute.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 32 of
47

33
On June 21, 2019, the T-1 Elbow allegedly failed and caused an explosion at the refinery, resulting
in considerable property damage. See Joint Pretrial Order § G, ¶ 32. The United States Chemical
Safety Board retained Anamet Labs, a metallurgical-testing laboratory specializing in failure
analysis and mechanical testing, to investigate the causes of the explosion. See Trial Tr. 102:18–
103:2 (Apr. 11, 2025) (Carnahan); Stipulated Ex. 51. Anamet Labs issued a report detailing its
findings after examining the T-1 and T-2 Elbows, the T-3 and T-4 Pipes, and the welds that joined
the T-1 to T-2, T-2 to T-3, and T-1 to T-4. See Stipulated Ex. 51, §§ 1.1–2.2. At the time of the
explosion, all four of those component parts had been in service since installation in the early
1970s. See Trial Tr. 103:7–104:11 (Apr. 11, 2025) (Carnahan). Anamet Labs measured the
chemical composition of all four component parts and found that the T-2 Elbow, the T-3 Pipe, and
the T-4 Pipe “met the chemical compositions requirements of the current versions of ASTM A234,
and ASTM A106 in addition to the guidelines on residual elements in API 571.” Stipulated Ex.
51, § 1.1. As to the chemical composition of the T-1 Elbow, Anamet Labs found:
Accelerated corrosion of the ruptured elbow T1 conformed to industry experience
with carbon steel components that contain elevated levels of the residual elements
nickel and copper as described in API 571 and API 751. The chemical composition
of the ruptured elbow T1 met the chemical composition requirements of ASTM
A234 in 1965, but did not meet the requirements of the 2015 version of the standard
or the guidelines regarding residual elements in API 571 because the nickel and
copper concentrations were greater than allowed.
Id.
The PES Entities, led by Mr. Kemeny, also performed their own internal investigation and
identified a “root cause” of the explosion to be: “Elbow Failure—Incorrect metallurgy of elbow
when the Unit was first build in 1973, in this cold Hydrocarbon/ HF Acid service system, counter
to the original design pipe specification at time of Unit construction.” Stipulated Ex. 71, at 4,
[ECF Doc. 241 & 251]; see also Trial Tr. 163:21–165:25 (Apr. 8, 2025) (Kemeny). Citing Anamet
Labs’ metallurgical data on the T-1 through T-4 parts as well as the welds connecting them, the
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 33 of
47

34
PES Entities’ internal investigation found that the T-1 Elbow contained levels of residual elements
copper and nickel over 50 times higher than the T-2 Elbow, T-3 Pipe, and T-4 Pipe, each of which
charted very low levels of those residual elements. See Stipulated Ex. 71, at 9; Trial Tr. 166:1–
167:3 (Apr. 8, 2025) (Kemeny).23
In other words, in 1972, Southwest Fabricating & Welding Co. fabricated the pipe spool
comprised of the T-1 and T-2 Elbows and the T-3 and T-4 Pipes for installation in the N-01 Circuit
of Unit 433. See Trial Tr. 70:3–71:19 (Apr. 10, 2025) (Stevick); Stipulated Ex. 18. Each of the
component parts surrounding the T-1 Elbow were made of 1965 ASTM 234 carbon steel
(incorporating 1968 A106 specifications). The T-1 Elbow was not.24
G. The Pennsylvania State Court Action and the Adversary Proceeding
On February 26, 2021, the PES Entities filed a lawsuit in a Pennsylvania state court against
the Reorganized B&W and affiliates, alleging that B&W’s T-1 Elbow installed in Unit 433 failed
and caused the June 2019 explosion; the PES Entities asserted negligence and products-liability
claims against the defendants. See Joint Pretrial Order § G, ¶ 33. On April 28, 2021, the
Reorganized B&W obtained leave of this Court to reopen B&W’s bankruptcy case and initiated
23 The welds between the T-1 Elbow and the T-2 Elbow as well as the T-1 Elbow and the T-4 Pipe
also revealed elevated levels of copper and nickel. See Stipulated Ex. 71, at 9; Trial Tr. 167:4–14 (Apr. 8,
2025) (Kemeny) (“An interesting one is the T1–T2 weld. You can see that showing higher levels. And
that’s because when welding between two different metallurgies, you’re basically melting some of the metal
from each side, and that’s why that weld is showing higher levels of copper and nickel. Likewise, a similar
type situation with the T1 to T4 connection, you’re again getting some mixing of the copper and nickel
from that one metallurgy elbow versus the very low nickel-copper containing components.”).
24 ASTM 234 carbon steel (incorporating 1968 A106 specifications) required Grade B carbon steel to
contain a maximum of 0.30% carbon, between 0.29 to 1.06% manganese, a maximum of 0.048%
Phosphorus, a maximum of 0.058% sulfur, and a minimum of 0.10% silicon. See Joint Ex. 171B & Table
I. The T-1 Elbow contained 0.14% carbon (compared with 0.24–0.25% carbon in the T-2, T-3, and T-4
components), 0.80% manganese, less than 0.005% phosphorus, 0.010% sulphur, and 0.10% silicon. See
Stipulated Ex. 71, at 9. The T-1 Elbow also contained a 2.58% combination of copper and nickel—an
amount suggesting that it was purposefully added and certainly not contemplated to be present in Grade B
carbon steel in the late 1960s and early 1970s given the high-purity steel manufacturing methods prevalent
at that time. See supra Part I.A.2.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 34 of
47

35
the above-captioned adversary proceeding, seeking a declaratory judgment that the confirmed
Joint Plan discharged the claims alleged by the PES Entities in the Pennsylvania state court action
and enjoined the PES Entities from pursuing those claims. See Joint Pretrial Order § G, ¶ 35; [ECF
Doc. 1 & No. 00-10992, ECF Doc. 7865]. Since then, the proceedings in the Pennsylvania state
court action have been stayed. After the PES Entities filed an Answer to the Complaint, [ECF
Doc. 16], the parties engaged in extensive discovery and motion practice before trial.
PART II: CONCLUSIONS OF LAW
A. Burden of Proof
“It is a fundamental rule that the burden of proof in its primary sense rests upon the party
who, as determined by the pleadings, asserts the affirmative of an issue.” Rex-Tech Int’l, LLC v.
Rollings (In re Rollings), 451 F. App’x 340, 346 (5th Cir. 2011) (internal quotations and citation
omitted). If this were an ordinary action for injunctive and declaratory relief, then the burden of
proof would rest with the Reorganized Debtor as it initiated this declaratory judgment action. See
id. But as explained by one bankruptcy court:
This is no ordinary case . . . . It is difficult to describe because it doesn’t fit into
any particular legal cargo hold. It can be looked at either as an objection to
discharge or an objection to claims. If looked at as an objection to discharge, then
it is the complaining entity that has the burden of proof. In this instance, even
though [the reorganized debtor] is the plaintiff, it is [the creditor] that wants to be
excepted from the consequences of the confirmation order. Thus, viewed in this
way, the burden of proof belongs on [the creditor’s] deck. If this action is looked
at as an objection to claim, however, the burden of proof rests on different parties
at different times, but the ultimate burden of persuasion is always on the
claimant . . . .
An even more persuasive basis for placing the burden of proof on [the
creditor] is the general rule that when the true facts relating to a dispute are
particularly within the knowledge of one party, then the burden of proving an issue
lies with the knowledgeable party. [The reorganized debtor] should not have to
prove a negative.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 35 of
47

36
Waterman Steamship Corp v. Aguiar (In re Waterman Steamship Corp.), 200 B.R. 770, 774–75
(Bankr. S.D.N.Y. 1996) (citing FED. R. BANKR. P. 4005).25 The PES Entities carry the burden of
proof here to show that their products-liability claims are not prepetition bankruptcy claims
discharged by B&W’s confirmed Joint Plan and that, therefore, they are excepted from the
consequences of that confirmed Joint Plan.
B. The PES Entities Are Bound by the Discharge Injunction Imposed by the
Confirmed Joint Plan as Joint Venturers/Successors-in-Interest to the Girard
Point Refinery If the Claims Asserted against the Reorganized B&W in the
Pennsylvania State Court Action Are Prepetition Claims Discharged by the
Confirmed Joint Plan.
In their Answer, the PES Entities assert that they cannot be bound by the terms of the
confirmed Joint Plan. [ECF Doc. 16, ¶¶ 31 & 32].26 This Court disagrees.
25 It may appear that courts disagree on this issue. But cases in which courts find that the reorganized
debtor holds the burden of proof are typically cases where the creditor held undisputed prepetition
bankruptcy claims that were discharged in the debtor’s bankruptcy case and the reorganized debtor was
forced to petition the court to enforce the discharge injunction when the creditor continued attempts to
collect the debt post-confirmation. See, e.g., Mahoney v. Washinton Mut., Inc. (In re Mahoney), 368 B.R.
579, 590 (Bankr. W.D. Tex. 2007) (“The burden of proof is on the former debtor to establish by clear and
convincing evidence that [the] creditor violated the post-discharge injunction.”) Here, whether the PES
Entities’ products-liability claims are prepetition bankruptcy claims is the dispute.
26 In their Answer, the PES Entities assert:
Answering further, PES denies that its claims against B&W and the other defendants in the
State Court Action were discharged in B&W’s bankruptcy case, in whole or in part,
pursuant to the Plan, Confirmation Order, applicable law, or otherwise. PES denies that it
is barred from pursuing the claims in the State Court Action against B&W and the other
defendants in the State Court Action, and other responsible parties including B&W’s
insurers, in whole or in part, pursuant to the Plan, Confirmation Order, applicable law, or
otherwise. PES denies that it held a claim during the B&W bankruptcy case that was
subject to discharge under the Plan. Contrary to the assertions by B&W that the Failed
elbow Joint was designed, manufactured, marketed, purchased, and installed prior to
B&W’s bankruptcy filing in 2000 and therefore any claims relating to the Failed elbow
Joint were discharged upon confirmation of the Plan in 2006, PES’s claims did not come
into existence until at least June 21, 2019. Further, B&W’s discharge claim fails due to
lack of due process, notice and privity, as to PES. B&W also maintained and continues to
maintain claims-based insurance policies for PES’ claims and other similar future claims,
which inter alia, demonstrates that B&W did not contemplate nor believe that such claims
would be discharged by the Plan . . . .
. . . .
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 36 of
47

37
“Under res judicata, a final judgment on the merits of an action precludes the parties or
their privies from relitigating issues that were or could have been raised in that action.” Allen v.
McCurry, 449 U.S. 90, 94 (1980). “[A] bankruptcy order is entitled to the effect of res judicata.”
Republic Supply Co. v. Shoaf, 815 F.2d 1046, 1051 (5th Cir. 1987) (citing Southmark Props. v.
Charles House Corp., 742 F.2d 862, 869 (5th Cir. 1984)). Under the Fifth Circuit’s four-prong
test for application of res judicata, “the parties must be identical in both suits, the prior judgment
must have been rendered by a court of competent jurisdiction, there must have been a final
judgment on the merits and the same cause of action must be involved in both cases.” Nilsen v.
City of Moss Point, Miss., 701 F.2d 556, 559 (5th Cir. 1983) (en banc). Once those four elements
are met, this Court must also determine whether “the previously unlitigated claim could or should
have been brought in the earlier litigation.” D–1 Enters., Inc. v. Commercial State Bank, 864 F.2d
36, 38 (5th Cir. 1989); see also In re Intelogic Trace, Inc., 200 F.3d 382, 388 (5th Cir. 2000); In
re Howe, 913 F.2d 1138, 1145 (5th Cir. 1990).
The parties do not dispute that this Court held competent jurisdiction over B&W’s
bankruptcy proceeding or that the Order confirming the Joint Plan constituted a final judgment on
the merits. As to the first factor requiring the parties to be “identical in both suits,” the Fifth Circuit
does not require strict identity of parties for res judicata purposes. See Clifton v. Warnaco, Inc.,
Nos. 94-10226 & 94-10657, 1995 WL 295863, at *6 (5th Cir. Apr. 18, 1995). The preclusive
effect of the res judicata doctrine can be extended to persons or entities “in privity” with parties
to the litigation, which “is merely another way of saying that there is sufficient identity between
Answering further, PES denies the discharge injunction applies to PES’ claims in whole or
in part.
[ECF Doc. 16, ¶¶ 31 & 32].
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 37 of
47

38
parties to prior and subsequent suits for res judicata to apply.” Meza v. Gen. Battery Corp., 908
F.2d 1262, 1266 (5th Cir. 1990). Indeed, “[p]rivity is recognized as a broad concept, which
requires [a] look to the surrounding circumstances to determine whether claim preclusion is
justified.” Russell v. SunAmerica Sec., Inc., 962 F.2d 1169, 1173 (5th Cir. 1992). The Fifth Circuit
recognizes privity in three circumstances: “(1) where the non-party is the successor in interest to
a party’s interest in property; (2) where the non-party controlled the prior litigation; and (3) where
the non-party’s interests were adequately represented by a party to the original suit.” Meza, 908
F.2d at 1266.
The facts here reveal that Gulf Oil contracted for the construction of the Girard Point
Refinery in the early 1970s. In the early 1980s, Gulf Oil merged with Chevron, and, in 1994,
Chevron sold the Girard Point Refinery to Sunoco. B&W filed for chapter 11 bankruptcy relief
in February 2000. Sunoco remained the sole owner of the Girard Point Refinery until June 2012,
when it formed PES LLC with a private equity fund and a co-investment fund and contributed the
Girard Point Refinery to PES LLC. PES LLC, in turn, operated the Girard Point Refinery through
its wholly owned subsidiary, PESRM, formed for that purpose. On August 14, 2012, Sunoco
(n/k/a Sunoco (R&M), LLC), the Commonwealth of Pennsylvania Department of Environmental
Protection, and PESRM entered into a Consent Order and Agreement that transferred the Girard
Point Refinery to PESRM. Since then, Sunoco has maintained a minority membership interest in
PES LLC, whose wholly owned subsidiary, PESRM owns the Girard Point Refinery. The Court
thus finds that the PES Entities are joint venturers with or successors in interest to Sunoco’s interest
in the Girard Point Refinery and that Sunoco, having received notice of B&W’s bankruptcy and
participated in that proceeding, adequately represented the PES Entities’ interest in the B&W
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 38 of
47

39
bankruptcy. The Court finds that sufficient identity between Sunoco and the PES Entities exists
to justify the application of res judicata here.
The question, then, is whether “same cause of action [is] involved in both cases”—that is,
whether the claims alleged by the PES Entities against the Reorganized B&W in the Pennsylvania
state court action are prepetition claims that were discharged by the confirmed Joint Plan in
B&W’s bankruptcy case.
C. The Products-Liability Claims Asserted by the PES Entities Related to the T-1
Elbow Are Not Prepetition Bankruptcy Claims Discharged in B&W’s
Bankruptcy Case.
Section 1141 of the Bankruptcy Code outlines the effect of a confirmed plan of
reorganization. With a few exceptions not relevant here, and “[e]xcept as otherwise provided . . .
in the plan, or in the order confirming the plan, the confirmation of a plan discharges the debtor
from any debt that arose before the date of such confirmation.” 11 U.S.C. § 1141(d)(1)(A).
Section 524 of the Bankruptcy Code, describing the effect of a discharge, “shields a debtor from
personal liability on claims that are discharged in bankruptcy.” In re Valaris PLC, No. 20-34114,
2025 WL 392482, at *3 (Bankr. S.D. Tex. Feb. 4, 2025) (citing 11 U.S.C. § 524; In re Edgeworth,
993 F.2d 51, 53 (5th Cir. 1993)). Indeed, “[t]he debt itself is not extinguished, but the discharge
acts as an injunction against any action pursued by creditors to recover on a claim against the
debtor.” Id.
“Claim” is defined broadly in the Bankruptcy Code as a “right to payment, whether or not
such right is reduced to judgment, liquidated, unliquidated, fixed, contingent, matured, disputed,
undisputed, legal, equitable, secured, or unsecured.” 11 U.S.C. § 101(5). Although the
Bankruptcy Code defines a “claim” broadly, that definition is not limitless. A discharge injunction
does not bar the pursuit of all claims against the debtor; instead, “[a] bankruptcy discharge acts as
a permanent injunction against the holders of dischargeable claims against the Debtor.” In re
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 39 of
47

40
Barry, 330 B.R. 28, 36 (Bankr. D. Mass. 2005) (citing Bessette v. Avco Fin. Servs., Inc., 230 F.3d
439 (1st Cir. 2000)) (emphasis added). Defining the outer reaches of dischargeable claims
implicates due-process concerns.
1. Elements of the Fifth Circuit’s “prepetition-relationship” test
The first step when analyzing whether a claim was discharged by an Order confirming a
plan of reorganization is to determine whether the claim is a prepetition bankruptcy claim. See In
re United Ref. Co., No. 83-03935, 2021 WL 160433, at *2 (Bankr. S.D. Tex. Jan. 16, 2021), aff’d
and remanded sub nom. United Ref. Co. v. Dorrion, 688 F. Supp. 3d 558 (S.D. Tex. Aug. 23,
2023).27 The definition of “claim” in § 101(5) is broad enough to encompass future claims—that
is, claims “that have not manifested” at the time of confirmation of a plan of reorganization, “but
that are relatively certain to manifest in the future and are based on the prior acts of the debtor.”
Fairchild Aircraft Inc. v. Campbell (In re Fairchild Aircraft Corp.), 220 B.R. 909, 916 (Bankr.
W.D. Tex. 1998) (quoting NAT’L BANKR. REV. COMM’N, TREATMENT OF MASS FUTURE CLAIMS
IN BANKRUPTCY (1997)); see also Dorrion, 688 F. Supp. 3d at 564.28 Treating unknown future
27 Courts use ‘pre-petition claim’ and ‘pre-confirmation claim’ interchangeably. See, e.g., In re
AMPAM Power Plumbing, L.P., 520 B.R. 553, 558 (Bankr. W.D. Tex. 2014) (“As Wright instructs, pre-
petition and pre-confirmation claims are treated identically in the context of future claims.” (citing Wright
v. Owens Corning, 679 F.3d 101, 107 (3d Cir. 2012))).
28 “Indeed, the legislative history [of § 101(5)] unmistakably states that the language employed was
chosen so that ‘all legal obligations of the debtor, no matter how remote or contingent, will be able to be
dealt with in the bankruptcy case [to] permit[] the broadest possible relief in the bankruptcy court.’” In re
Fairchild Aircraft Corp., 184 B.R. 910, 924 (Bankr. W.D. Tex. 1995), vacated on other grounds, 220 B.R.
909 (Bankr. W.D. Tex. 1998) (quoting H.R. REP. No. 595, 95th Cong., 1st Sess. 309 (1977), reprinted in
1978 U.S.C.C.A.N. 5787, 5963, 6266). A contingent claim is a type of future claim. Although the
Bankruptcy Code does not define a contingent claim, the Fifth Circuit instructs:
A claim is contingent as to liability if the debtor’s legal duty to pay does not come into
existence until triggered by the occurrence of a future event and such future occurrence
was within the actual or presumed contemplation of the parties at the time the original
relationship of the parties was created.
In re All Media Props., Inc., 5 B.R. 126, 133 (Bankr. S.D. Tex. 1980), aff’d, 646 F.2d 193 (5th Cir. 1981).
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 40 of
47

41
claims in chapter 11 implicates two competing concerns: “the Bankruptcy Code’s goal of
providing a debtor with a fresh start by resolving all claims arising from the debtor’s conduct prior
to its emergence from bankruptcy; and the rights of individuals who may be damaged by that
conduct but are unaware of the potential harm at the time of the debtor’s bankruptcy.” Wright v.
Owens Corning, 679 F.3d 101, 105 (3d Cir. 2012). Against that backdrop, courts have developed
various tests for determining whether future claims meet the definition of “claim” under the
Bankruptcy Code.29 Acknowledging that “there must be evidence that would permit the debtor to
identify, during the course of the bankruptcy proceedings, potential victims and thereby permit
notice to these potential victims of the pendency of the proceedings,” the Fifth Circuit has applied
a “prepetition-relationship” test to determine whether a future prepetition claim exists. Lemelle v.
Universal Mfg. Corp., 18 F.3d 1268, 1277 (5th Cir. 1994) (citations omitted). That test requires
“some prepetition relationship, such as contact, exposure, impact, or privity, between the debtor’s
prepetition conduct and the claimant.” Id. (quoting In re Piper Aircraft Corp., 162 B.R. 619, 627
(Bankr. S.D. Fla. 1994)).30
29 Tests include (i) the “accrual” test, (ii) the “fair-contemplation” test, (iii) the “conduct” test, and
(iv) the “prepetition-relationship” test. “Under the accrual test, a claim accrues for bankruptcy purposes
when it accrues under applicable non-bankruptcy law.” Dorrion, 688 F. Supp. 3d at 563. “Under the fair-
contemplation test, for a claim to qualify as a prepetition claim, it must have been within the ‘fair
contemplation’ of the parties at the time of bankruptcy filing.” Id. “Under the conduct test, a bankruptcy
claim arises whenever the conduct prompting alleged liability occurs, even if injury doesn’t manifest itself
until after the bankruptcy filing.” Id. The prepetition-relationship test applied by the Fifth Circuit is
essentially a narrower version of the conduct test. See id. at 564.
30 B&W’s confirmed Joint Plan defined “Contingent Claim” broadly. See supra Part I.E. The
Reorganized B&W asserted in its second summary judgment motion that the Joint Plan’s terms discharged
the PES Entities’ current products-liability claims and preempts any inquiry otherwise. [ECF Docs. 209 &
210]. In denying summary judgment, the Court found:
The Court interprets B&W’s argument as one that would allow a debtor to
circumvent due process regarding future claims by drafting language in a plan that
obliterates any limit to the types of claims that are subject to a discharge injunction in a
confirmed plan. The Court rejects that assertion. To determine whether the claims asserted
by the Defendants in the Pennsylvania state court action are dischargeable prepetition
bankruptcy claims that were discharged through B&W’s confirmed Plan, this Court is
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 41 of
47

42
Cases applying the prepetition-relationship test are instructive to the Court’s determination
here. Compare the Lemelle and Piper Aircraft cases with the Dorrion case. In Lemelle,
[t]wo children had died in 1985 after a mobile home manufactured in 1970 by a
predecessor of defendant Universal Manufacturing caught fire. The mother of the
children brought a wrongful-death suit related to the fire. Universal Manufacturing
then sought summary judgment on account of a 1982 bankruptcy filing by the
predecessor corporation, arguing that the mother’s claim was discharged in
bankruptcy. The Fifth Circuit determined that a dischargeable claim didn’t exist at
the time of filing in part because “the injury and the manifestation of that injury
occurred simultaneously,” several years after the bankruptcy petition was filed. It
further explained that there was no evidence indicating “when [the mother] and her
family acquired th[e] mobile home or from whom they acquired it.” Nor was there
any evidence that the manufacturer “should have even known of [the mother’s] and
her family’s existence.” They were “completely unknown and unidentified” when
the bankruptcy petition was filed.
Dorrion, 688 F. Supp. 3d at 564 (summarizing the facts and holding in Lemelle, 18 F.3d, at 1271–
77). The Lemelle court concluded that “even the broad definition of ‘claim’ cannot be extended
to include . . . claimants whom the record indicates were completely unknown and unidentifiable
at the time [debtor] filed its petition and whose rights depended entirely on the fortuity of future
occurrences.” 18 F.3d at 1277. Similarly, the Piper Aircraft debtor entered chapter 11 and,
[a]ssuming that aircraft designed and manufactured by Piper pre-petition would
crash and injure persons and property post-petition, a legal representative filed a
proof of claim on behalf of potential future claimants for $100 million . . . based on
statistical assumptions regarding the number of people who were likely to suffer
personal injury or property damage after Piper’s reorganization plan was
confirmed.
required to apply the Fifth Circuit’s prepetition-relationship test after hearing the parties’
evidence as to the two conditions that must exist to satisfy that test. Due process demands
it.
[ECF Doc. 236]. As it stands, the evidence at trial has revealed that the PES Entities’ products-liability
claims are not dischargeable prepetition bankruptcy claims.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 42 of
47

43
Lemelle, 18 F.3d at 1276 (summarizing the facts in Piper Aircraft Corp., 162 B.R. at 621–22). In
finding that the future claimants had no prepetition bankruptcy claim that could be affected by an
Order confirming Piper Aircraft’s reorganization plan, the Piper Aircraft court observed:
We know that some planes in the existing fleet of Piper Aircraft will crash, and we
know that there may be injuries, deaths and property damage as a result. We also
know that under theories of negligence and products liability, Piper, if it remains in
existence, would be liable for some of these damages. Even so, there is no way to
identify who the victims will be or to identify any particular prepetition contact,
exposure, impact, privity or other relationship between Piper and these potential
claimants that will give rise to these future damages.
162 B.R. at 627.
Those cases tell us that, to find a future claim to be a dischargeable prepetition bankruptcy
claim under the prepetition-relationship test, two conditions must exist: (1) the future injury must
be relatively certain to manifest itself at some point and be attributable to the debtor and (2) the
debtor must be able to identify the claimant to whom it can give notice sufficient to satisfy due
process that his or her future claim might be discharged by a confirmation order. The holding in
Dorrion demonstrates this. In affirming the bankruptcy court’s finding that the confirmation order
discharged a future claimant’s claim, the district court recounted evidence that the debtor knew of
both its asbestos-related liability and how to identify potential future claimants:
The Decedent was employed by United Refining [the debtor] at one of its plants in
the 1960s. He was exposed to asbestos during such employment. Even the
Executor recognizes that United Refining was no doubt aware of the dangers of
asbestos exposure by the time of its 1983 bankruptcy filing, with asbestos-related
lawsuits against it and many others having been well underway by then. By virtue
of his employment, then, the Decedent was neither unknown nor unidentifiable.
And the conduct at issue—exposure to asbestos by United Refining—occurred
prepetition. The Executor’s claim thus existed prepetition, even though the
Decedent’s injury manifested itself post-petition.
. . . .
On the available record, the bankruptcy court didn’t err by determining that
the Decedent’s estate had sufficient notice of the need to file a bankruptcy claim.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 43 of
47

44
Dorrion, 688 F. Supp. 3d at 564 & 566.
2. The PES Entities’ claims are not dischargeable prepetition bankruptcy claims.
In the present case, the sufficiency of B&W’s notice to the PES Entities that a future claim
might be discharged is not an issue. B&W provided actual notice of its bankruptcy case and the
bar date to Sunoco, the owner of the Girard Point Refinery which housed the T-1 Elbow. Sunoco
participated in B&W’s bankruptcy case and filed a proof of claim against the estate. As discussed
above, the PES Entities share sufficient identity with Sunoco to be bound by the terms of the Joint
Plan if the Pennsylvania state action claims are indeed prepetition bankruptcy claims that have
been discharged through confirmation of the Joint Plan. And, solely for purposes of the task before
this Court, no one contests that the alleged future injury is attributable to B&W: B&W
manufactured the T-1 Elbow that was installed as a component part of Unit 433 in the early
1970s—years before B&W filed for bankruptcy relief—and then the T-1 Elbow allegedly failed
post-confirmation in 2019 and caused the explosion at the Girard Point Refinery. That leaves open
one remaining element of the prepetition-relationship test: whether any injury related to the T-1
Elbow manufactured by B&W was relatively certain to manifest at some point. Thus, the Court
must evaluate the evidence gathered over the four-day trial to determine whether the PES Entities’
products-liability claims related to the T-1 Elbow are like the claims in Dorrion where the nature
and scope of those injuries was known or foreseeable to B&W’s estate—or are they more akin to
the claims in Lemelle where “the injury and the manifestation of that injury occurred
simultaneously” years after the bankruptcy case was filed.
The evidence at trial revealed that the PES Entities’ products-liability claims related to the
T-1 Elbow were not known or foreseeable to Sunoco at the time of B&W’s bankruptcy case.
Today’s refining-industry knowledge accepts that (i) the presence of high percentages of residual
elements such as nickel and copper in steel interferes with the integrity and functioning of steel
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 44 of
47

45
piping systems installed in hydrofluoric-acid environments and (ii) those elevated percentages of
residual elements originate from manufacturers’ heavy reliance upon scrap metal to forge steel
using electric furnaces starting in the mid-1980s. See, e.g., Joint Ex. 181, at 18 (“The significance
of this transition [increasing electric-furnace steelmaking] is that a much more substantial
percentage of steel is now being produced by electric furnace melting, a scrap intensive process,
and scrap is the principal source of residual elements.”). But the refining industry was just waking
up to that reality in the early 2000s when B&W filed and prosecuted its chapter 11 bankruptcy
case. Operators of hydrofluoric-acid alkylation units would have been reasonable in assuming that
piping systems installed in such units prior to the mid-1980s—before the widespread use of electric
furnaces and high percentages of scrap metal to forge steel—were made of high-purity carbon steel
and thus extremely resistive to corrosion. See Trial Tr. 57:9–58:15 (Apr. 11, 2025) (Reynolds);
Trial Tr. 116:6–16 (Apr. 11, 2025) (Carnahan).
But specific to this case, Gulfco, Chevron, and Sunoco nevertheless fulfilled RAGAREP
standards for inspection of hydrofluoric-acid alkylation unit piping systems by increasing TMLs
over time in response to gradually emerging data on the negative effects of residual elements on
piping systems in those units. That diligence revealed no thinning or corrosion concerns in the N-
01 Circuit as late as 2001. Indeed, although the T-1 Elbow was not the site of a TML itself, Sunoco
regularly measured the T-2 Elbow welded adjacent to the T-1 Elbow and found no significant
corrosion. No one could have predicted as of the June 2003 bar date in B&W’s bankruptcy case
that the T-1 Elbow was not made of the same A234 Grade B carbon steel as its sibling T-2, T-3,
and T-4 component parts, fabricated by Southwest Fabricating Co. and installed together as one
unit in the N-01 Circuit in the early 1970s.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 45 of
47

46
Moreover, no statistical or other evidence is before the Court to suggest that the T-1 Elbow
manufactured by B&W was destined to fail. Indeed, it performed for over 45 years before the
June 2019 explosion at the Girard Point Refinery. Compare Dorrion, 688 F. Supp. 3d at 564
(“Even the Executor recognizes that United Refining was no doubt aware of the dangers of
asbestos exposure by the time of its 1983 bankruptcy filing, with asbestos-related lawsuits against
it and many others having been well underway by then.”) and Piper Aircraft Corp., 162 B.R. at
621 (“Over the years, Piper has been a defendant in several lawsuits based on its manufacture,
design, sale, distribution and support of aircraft and parts. . . . With 50,000 or 60,000 Piper aircraft
still in operation, accidents involving these aircraft undoubtedly will occur.”), with Lemelle, 18
F.3d at 1276 (“The injury suffered, i.e., the death of the decedents, occurred simultaneously with
the manifestation of that injury in December 1985, years after Winson’s reorganization plan had
been confirmed. The design and manufacture of the mobile home in question thus result in no
tortious consequence until a fire started in that mobile home in December 1985.”). The Court finds
that the injury caused by the alleged failure of the T-1 Elbow was not relatively certain to manifest
at some point. Thus, the PES Entities’ current products-liability claims fail the prepetition-
relationship test and are not prepetition bankruptcy claims discharged by B&W’s confirmed Joint
Plan. The PES Entities are not enjoined by the confirmed Joint Plan from pursuing those claims
in the Pennsylvania state court action.
Accordingly,
IT IS ORDERED that the sole count alleged by the Reorganized B&W in its declaratory
action is DENIED.
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 46 of
47

47
The Court will enter a separate judgment against the Reorganized Babcock & Wilcox
contemporaneously with this Memorandum Opinion and Order.
New Orleans, Louisiana, June 13, 2026.
__________________________________________
MEREDITH S. GRABILL
UNITED STATES BANKRUPTCY JUDGE
Case 21-01014 Doc 288 Filed 06/13/26 Entered 06/13/26 21:55:57 Main Document Page 47 of
47