Table of Contents
Index to Financial Statements
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 2023
or
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-32740
Delaware
(State or other jurisdiction of incorporation or organization)
30-0108820
(I.R.S. Employer Identification No.)
ENERGY TRANSFER LP
(Exact name of registrant as specified in its charter)
8111 Westchester Drive, Suite 600, Dallas, Texas 75225
(Address of principal executive offices) (zip code)
Title of each class
Common Units
7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units
7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units
7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable
Perpetual Preferred Units
9.250% Series I Fixed Rate Perpetual Preferred Units
Registrant’s telephone number, including area code: (214) 981-0700
Securities registered pursuant to Section 12(b) of the Act:
Trading Symbol(s)
ET
Name of each exchange on which registered
New York Stock Exchange
ETprC
ETprD
ETprE
ETprI
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
New York Stock Exchange
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T
during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth
company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange
Act.
Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial
reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the
correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the
registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value as of June 30, 2023, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such
Common Units on the New York Stock Exchange on such date, was $35.67 billion.
As of February 9, 2024, the registrant had 3,367,757,556 Common Units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
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Index to Financial Statements
FORM 10-K
ENERGY TRANSFER LP AND SUBSIDIARIES
TABLE OF CONTENTS
ITEM 1. BUSINESS
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1C. CYBERSECURITY
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
ITEM 4. MINE SAFETY DISCLOSURES
PART I
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES
ITEM 6. [RESERVED]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER
MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART III
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
ITEM 16. FORM 10-K SUMMARY
SIGNATURES
PART IV
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93
93
94
95
98
99
100
100
129
133
133
133
135
135
136
142
157
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Index to Financial Statements
Definitions
The following is a list of certain acronyms and terms used throughout this document:
/d
Adjusted EBITDA
AOCI
AROs
BBtu
Bcf
Btu
Capacity
Citrus
Crestwood
Dakota Access
DOE
DOJ
DOT
Enable
Energy Transfer Canada
Energy Transfer GC NGL
Energy Transfer Preferred
Units
Energy Transfer R&M
EPA
ETC Sunoco
ETO
ETP Holdco
Exchange Act
Explorer
FEP
FERC
FGT
GAAP
General Partner
HFOTCO
IDRs
IFERC
IRS
Lake Charles LNG
Lake Charles LNG Export
LIBOR
per day
a non-GAAP measure defined as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash
items, as further described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations – Results of Operations”
accumulated other comprehensive income
asset retirement obligations
billion British thermal units
billion cubic feet
British thermal unit, an energy measurement used by gas companies to convert the volume of gas used to its heat
equivalent, and thus calculate the actual energy content
capacity of a pipeline, processing plant or storage facility refers to the maximum capacity under normal operating
conditions and, with respect to pipeline transportation capacity, is subject to multiple factors (including natural gas
injections and withdrawals at various delivery points along the pipeline and the utilization of compression) which may
reduce the throughput capacity from specified capacity levels
Citrus, LLC, a 50/50 joint venture which owns FGT
Crestwood Equity Partners LP
Dakota Access, LLC, a non-wholly owned subsidiary of Energy Transfer
United States Department of Energy
United States Department of Justice
United States Department of Transportation
Enable Midstream Partners, LP
Energy Transfer Canada ULC, a non-wholly owned subsidiary of Energy Transfer until its sale in August 2022
Energy Transfer GC NGLs LLC, formerly Lone Star NGL LLC, a wholly owned subsidiary of Energy Transfer
Collectively, the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units,
Series E Preferred Units, Series F Preferred Units, Series G Preferred Units, Series H Preferred Units and Series I Preferred
Units
Energy Transfer (R&M), LLC (formerly Sunoco (R&M), LLC)
United States Environmental Protection Agency
ETC Sunoco Holdings LLC (formerly Sunoco, Inc.), a wholly owned subsidiary of Energy Transfer
Energy Transfer Operating, L.P., formerly a non-wholly owned subsidiary of Energy Transfer until its merger into the
Partnership in April 2021
ETP Holdco Corporation, a wholly owned subsidiary of Energy Transfer
Securities Exchange Act of 1934, as amended
Explorer Pipeline and/or Explorer Pipeline Company
Fayetteville Express Pipeline LLC
United States Federal Energy Regulatory Commission
Florida Gas Transmission Pipeline and/or Florida Gas Transmission Company, LLC, a wholly owned subsidiary of Citrus
accounting principles generally accepted in the United States of America
LE GP, LLC, the general partner of Energy Transfer
HFOTCO LLC, a wholly owned subsidiary of Energy Transfer, which owns the Houston Terminal
incentive distribution rights
Inside FERC’s Gas Market Report
United States Internal Revenue Service
Lake Charles LNG Company, LLC, a wholly owned subsidiary of Energy Transfer
Lake Charles LNG Export Company, LLC, a wholly owned subsidiary of Energy Transfer
London Interbank Offered Rate
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LNG
Lotus Midstream
MBbls
MEP
Mid Valley
MMBbls
MMcf
MTBE
NGA
NGL
NGPA
NuStar
NYMEX
NYSE
ORS
OSHA
OTC
Panhandle
Partnership Agreement
PCBs
PEP
PHMSA
Preferred Unitholders
Rover
SCOOP
Sea Robin
SEC
Series A Preferred Units
Series B Preferred Units
Series C Preferred Units
Series D Preferred Units
Series E Preferred Units
Series F Preferred Units
Series G Preferred Units
Series H Preferred Units
Series I Preferred Units
SESH
SOFR
Southwest Gas
SPLP
liquefied natural gas
Lotus Midstream Operations, LLC
thousand barrels
Midcontinent Express Pipeline LLC
Mid Valley Pipeline Company LLC, a wholly owned subsidiary of Energy Transfer
million barrels
million cubic feet
methyl tertiary butyl ether
Natural Gas Act of 1938
natural gas liquid, such as propane, butane and natural gasoline
Natural Gas Policy Act of 1978
NuStar Energy L.P.
New York Mercantile Exchange
New York Stock Exchange
Ohio River System LLC, a non-wholly owned subsidiary of Energy Transfer
Federal Occupational Safety and Health Act
over-the-counter
Panhandle Eastern Pipe Line Company, LP, a wholly owned subsidiary of Energy Transfer
Energy Transfer’s Fourth Amended and Restated Agreement of Limited Partnership, as amended to date
polychlorinated biphenyls
Permian Express Partners LLC, a non-wholly owned subsidiary of Energy Transfer
Pipeline Hazardous Materials Safety Administration
Unitholders of the Series A Preferred Units, Series B Preferred Units, Series C Preferred Units, Series D Preferred Units,
Series E Preferred Units, Series F Preferred Units, Series G Preferred Units, Series H Preferred Units and Series I Preferred
Units, collectively
Rover Pipeline and/or Rover Pipeline LLC, a non-wholly owned subsidiary of Energy Transfer
South Central Oklahoma Oil Province
Sea Robin Pipeline and/or Sea Robin Pipeline Company, LLC, a wholly owned subsidiary of Energy Transfer
United States Securities and Exchange Commission
Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units
Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series I Fixed-Rate Perpetual Preferred Units
Southeast Supply Header Pipeline and/or Southeast Supply Header, LLC, a non-wholly owned subsidiary of Energy
Transfer
Secured overnight financing rate
Pan Gas Storage, LLC (d.b.a. Southwest Gas Storage Company), a wholly owned subsidiary of Energy Transfer
Sunoco Pipeline L.P., a wholly owned subsidiary of Energy Transfer
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Tiger
Transwestern
TRRC
Trunkline
Unitholders
USAC
White Cliffs
Tiger Pipeline and/or ETC Tiger Pipeline, LLC, a wholly owned subsidiary of Energy Transfer
Transwestern Pipeline and/or Transwestern Pipeline Company, LLC, a wholly owned subsidiary of Energy Transfer
Texas Railroad Commission
Trunkline Pipeline and/or Trunkline Gas Company, LLC, a wholly owned subsidiary of Energy Transfer
Preferred Unitholders and holders of Energy Transfer LP common units
USA Compression Partners, LP, a publicly traded partnership and consolidated subsidiary of Energy Transfer
White Cliffs Pipeline, L.L.C.
Forward-Looking Statements
Certain matters discussed in this annual report, excluding historical information, as well as some statements by Energy Transfer LP (the “Partnership” or
“Energy Transfer”) in periodic press releases and some oral statements of the Partnership’s officials during presentations about the Partnership, include
forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts.
Statements using words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “continue,” “could,” “believe,” “may,”
“will” or similar expressions help identify forward-looking statements. Although the Partnership and its General Partner believe such forward-looking
statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that such
assumptions, expectations or projections will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and
assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, the Partnership’s actual results may
vary materially from those anticipated, estimated, projected, forecasted, expressed or expected in forward-looking statements since many of the factors that
determine these results are subject to uncertainties and risks that are difficult to predict and beyond management’s control. For additional discussion of
risks, uncertainties and assumptions, see “Item 1A. Risk Factors” included in this annual report.
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Overview
PART I
ITEM 1. BUSINESS
Energy Transfer LP is a Delaware limited partnership with common units publicly traded on the NYSE under the ticker symbol “ET.”
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “Energy Transfer” mean Energy Transfer LP and its
consolidated subsidiaries, which include Sunoco LP and USAC.
The primary activities in which we are engaged, which are located in the United States, are as follows:
•
natural gas operations, including the following:
•
•
natural gas midstream and intrastate transportation and storage;
interstate natural gas transportation and storage; and
•
crude oil, NGL and refined products transportation, terminalling and acquisition and marketing activities as well as NGL storage and fractionation
services.
In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are master limited partnerships.
Energy Transfer derives cash flows from distributions related to its investment in its subsidiaries, including Sunoco LP and USAC. The amount of cash that
our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary
cash requirements are for distributions to its partners, general and administrative expenses and debt service requirements. Energy Transfer distributes its
available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and
working capital needs; however, Energy Transfer may issue debt or equity securities from time to time as we deem prudent to provide liquidity for new
capital projects of our subsidiaries or for other partnership purposes.
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The following chart summarizes our organizational structure as of February 9, 2024. For simplicity, certain entities and ownership interests have not been
depicted.
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Significant Achievements in 2023
Strategic Transactions
•
•
In November, the Partnership completed its acquisition of Crestwood, which owns gathering and processing assets located in the Williston, Delaware
and Powder River basins.
In May, the Partnership acquired Lotus Midstream, which owns an integrated crude midstream platform located in the Permian Basin.
Organic Growth Projects
•
•
In August, the Partnership’s eighth fractionator was placed in service at the Mont Belvieu NGL Complex, which brings fractionation capacity at Mont
Belvieu to approximately 1.15 MMBbls/d.
In June, the Partnership’s 200 MMcf/d Bear cryogenic processing plant was placed in service in the Permian Basin.
Segment Overview
See Note 16 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional financial
information about our segments.
Intrastate Transportation and Storage Segment
Intrastate natural gas transportation pipelines receive natural gas from other mainline transportation pipelines, storage facilities and gathering systems, and
deliver the natural gas to industrial end-users, storage facilities, utilities, power generators and other third-party pipelines. Through our intrastate
transportation and storage segment, we own and operate (through wholly owned subsidiaries or through joint venture interests) approximately 12,200 miles
of intrastate natural gas transportation pipelines with approximately 24 Bcf/d of transportation capacity, three natural gas storage facilities located in Texas
and two natural gas storage facilities located in Oklahoma.
Energy Transfer operates one of the largest intrastate pipeline systems in the United States, which provides energy logistics to major trading hubs and
industrial consumption areas throughout the country. In Texas, our intrastate transportation and storage segment provides transportation of natural gas to
major markets from various prolific natural gas producing areas in Texas and Louisiana (Permian Basin and Barnett, Haynesville and Eagle Ford shales)
through our Oasis Pipeline, ETC Katy Pipeline, Lobo Pipeline, RIGS and Pelico Pipeline as well as our two natural gas pipeline and storage systems: ET
Fuel and HPL. In Oklahoma, we operate Oklahoma Intrastate Transmission, which delivers natural gas from various shale plays in the Anadarko and
Arkoma basins, as further described in “Asset Overview.”
We also own a 70% interest in Red Bluff Express Pipeline, which owns a pipeline in the Delaware Basin, and 16% membership interests in Comanche Trail
Pipeline and Trans-Pecos Pipeline, which own pipelines delivering natural gas from the Waha Hub to the United States/Mexico border.
Our intrastate transportation and storage segment’s results are determined primarily by the amount of capacity our customers reserve as well as the actual
volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a
fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer
to pay a fee even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput
of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline or (iv) a combination of the three, generally
payable monthly.
We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial
end-users and marketing companies. Generally, we purchase natural gas from either the market (including purchases from our marketing operations) or
from producers at the wellhead. To the extent the natural gas comes from producers, it is primarily purchased at a discount to a specified market price and
typically resold to customers based on an index price. In addition, our intrastate transportation and storage segment generates revenues from fees charged
for storing customers’ working natural gas in our storage facilities and from managing natural gas for our own account.
Interstate Transportation and Storage Segment
Interstate natural gas transportation pipelines receive natural gas from supply sources including other transportation pipelines, storage facilities and
gathering systems, and deliver the natural gas to industrial end-users and other pipelines. Through our interstate transportation and storage segment, we
directly own and operate approximately 20,090 miles of interstate natural gas
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pipelines with approximately 20.1 Bcf/d of transportation capacity and another approximately 7,085 miles and 12.3 Bcf/d of transportation capacity
through joint venture interests.
Our vast interstate natural gas network spans the United States from Florida to California and Texas to Michigan, offering a comprehensive array of
pipeline and storage services. Our pipelines have the capability to transport natural gas from nearly all Lower 48 onshore and offshore supply basins to
customers in the Gulf Coast, Southeast, Southwest, Midwest and Northeast United States as well as Canada. Through numerous interconnections with other
pipelines, our interstate systems can access virtually any supply or market in the country. As discussed further herein, our interstate transportation and
storage segment’s operations are regulated by the FERC, which has broad regulatory authority over the business and operations of interstate natural gas
pipelines.
Lake Charles LNG, our wholly owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake
Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground storage capacity and the regasification facility has a send-out capacity
of 1.8 Bcf/d. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly owned subsidiary of Royal Dutch Shell plc
(“Shell”).
Lake Charles LNG Export, our wholly owned subsidiary, is developing a natural gas liquefaction project at the site of our Lake Charles LNG import
terminal and regasification facility. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles
site. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March
2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. The project will benefit from the
infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets.
During 2022, Lake Charles LNG Export executed six LNG off-take agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year
LNG agreement with Shell NA LNG LLC. The agreements allow either party to terminate the agreement if Lake Charles LNG Export has not satisfied
specified conditions by a specified date. One of those conditions relates to Lake Charles LNG Export making a “final investment decision” to proceed with
the construction of the liquefaction facility. To date, the specified dates for satisfying these conditions have been extended by mutual agreement of the
parties to the agreements. We have also signed nonbinding letter agreements with several customers for LNG offtake, and we are in discussions with
several parties for potential long-term LNG offtake and potential equity investments in the project.
The results from our interstate transportation and storage segment are primarily derived from the fees we earn from natural gas transportation and storage
services.
Midstream Segment
The midstream industry consists of natural gas gathering, compression, treating, processing, storage and transportation, and is generally characterized by
regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells and the proximity of storage
facilities to production areas and end-use markets. Gathering systems generally consist of a network of small diameter pipelines and, if necessary,
compression systems, that collect natural gas from points near producing wells and transports it to larger pipelines for further transportation.
Treating plants remove carbon dioxide and hydrogen sulfide from natural gas that is higher in carbon dioxide, hydrogen sulfide or certain other
contaminants, to ensure that it meets pipeline quality specifications. Natural gas processing involves the separation of natural gas into pipeline quality
natural gas, or residue gas, and a mixed NGL stream. Some natural gas produced by a well does not meet the pipeline quality specifications established by
downstream pipelines or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas can be
processed to take advantage of favorable margins for NGLs extracted from the gas stream.
Through our midstream segment, we own and operate (through wholly owned subsidiaries or joint venture interests) natural gas gathering pipelines, natural
gas processing plants, natural gas treating facilities and natural gas conditioning facilities with an aggregate processing capacity of approximately 11.4
Bcf/d. Our midstream segment focuses on the gathering, compression, treating, blending and processing of natural gas, and our operations are currently
concentrated in major producing basins and shales in Texas, New Mexico, West Virginia, Pennsylvania, Ohio, Oklahoma, Arkansas, Kansas, Louisiana,
Montana, North Dakota and Wyoming. Many of our midstream assets are integrated with our intrastate transportation and storage assets as well as our
NGL assets.
Our midstream segment’s results are derived primarily from margins we earn from natural gas volumes that are gathered, transported, purchased and sold
through our pipeline systems and the natural gas and NGL volumes processed at our processing and treating facilities.
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NGL and Refined Products Transportation and Services Segment
Our NGL and refined products operations transport, store and execute acquisition and marketing activities utilizing a complementary network of pipelines,
storage and blending facilities as well as strategic offtake locations that provide access to multiple markets.
Our NGL and refined products transportation and services segment includes:
•
•
•
approximately 5,700 miles of NGL pipelines;
our Nederland Terminal and connecting pipelines which provide transportation of ethane, propane, butane and natural gasoline from our Mont Belvieu
NGL Complex to our Nederland Terminal where these products can be exported;
our Marcus Hook Terminal which includes fractionation, storage and exporting assets. This facility is connected to our Mariner East Pipeline System,
which provides for the transportation of ethane and liquefied petroleum gas (“LPG”) products from western Pennsylvania, West Virginia and eastern
Ohio to our Marcus Hook Terminal where these component products can be exported, processed or locally distributed;
• NGL fractionation facilities at our Mont Belvieu NGL Complex with an aggregate capacity of 1.15 MMBbls/d;
• NGL storage facilities at our Mont Belvieu NGL Complex with a working storage capacity of approximately 60 MMBbls; and
•
other NGL storage assets with an aggregate storage capacity of approximately 35 MMBbls, including LPG storage assets acquired in connection with
the Crestwood acquisition in 2023.
Our NGL pipelines primarily transport NGLs from the Permian Basin, the Barnett and Eagle Ford shales to Mont Belvieu, Texas. In the Northeast, our
NGL pipelines transport from the Marcellus and Utica shales to our Marcus Hook Terminal, to customer facilities in Marysville, Michigan and to delivery
points on the Canadian border.
In addition to providing storage capacity, our NGL terminalling services also support our liquids blending activities, including the use of our patented
butane blending technology. Refined products operations provide transportation and terminalling services through the use of approximately 3,760 miles of
refined products pipelines and 37 active refined products marketing terminals. Our refined product marketing terminals are located primarily in the
Northeast, Midwest and Southwest United States, with approximately 8 MMBbls of refined products storage capacity. Our refined products operations
utilize our integrated pipeline and terminalling assets, as well as acquisition and marketing activities, to service refined products markets in several regions
throughout the United States. The mix of products delivered through our refined products pipelines varies seasonally, with gasoline demand peaking during
the summer months, and demand for heating oil and other distillate fuels peaking in the winter. The products transported in these pipelines include multiple
grades of gasoline and middle distillates, such as heating oil, diesel and jet fuel. Rates for shipments on these product pipelines are regulated by the FERC
and other state regulatory agencies, as applicable.
Revenues in this segment are principally generated from fees charged to customers under dedicated contracts or take-or-pay contracts. Under a dedicated
contract, the customer agrees to deliver the total output from particular processing plants that are connected to the NGL pipeline. Take-or-pay contracts
have minimum throughput commitments requiring the customer to pay regardless of whether a fixed volume is transported. Fees are market-based,
negotiated with customers and competitive with regional regulated pipelines and fractionators. Storage revenues are derived from base storage and
throughput fees. This segment also derives revenues from fee-based export activities, the marketing of NGLs as well as processing and fractionating
refinery off-gas.
Crude Oil Transportation and Services Segment
Our crude oil operations provide transportation (via pipeline and trucking), terminalling as well as acquisition and marketing services to crude oil markets
throughout the Southwest, Midwest and Northeast United States. Through our crude oil transportation and services segment, we own and operate (through
wholly owned subsidiaries or joint venture interests) approximately 14,500 miles of crude oil trunk and gathering pipelines in the Southwest, Midcontinent
and Midwest United States. This segment includes equity ownership interests in seven crude oil pipeline systems: the Bakken Pipeline, Bayou Bridge
Pipeline, White Cliffs Pipeline, Maurepas Pipeline, the Permian Express pipelines, Enable South Central Pipeline and the Wink to Webster Pipeline. Our
crude oil terminalling services operate with an aggregate storage capacity of approximately 65 MMBbls, including approximately 30 MMBbls at our Gulf
Coast terminal in Nederland, Texas, approximately 18.2 MMBbls at our Gulf Coast terminal on the Houston Ship Channel and approximately 9.5 MMBbls
at our Cushing Terminal in Cushing, Oklahoma, among others. Our crude oil acquisition and marketing activities utilize our pipeline and terminal assets,
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our proprietary fleet of crude oil tractor trailers and truck unloading facilities, as well as third-party assets to service crude oil markets principally in the
Midcontinent United States.
Revenues throughout our crude oil pipeline systems are generated from tariffs paid by shippers utilizing our transportation services. These tariffs are filed
with the FERC and other state regulatory agencies, as applicable.
Our crude oil acquisition and marketing activities include the gathering, purchasing, marketing and selling of crude oil. Specifically, the crude oil
acquisition and marketing activities include:
•
•
•
•
purchasing crude oil at both the wellhead from producers and in bulk from aggregators at major pipeline interconnections and trading locations;
storing inventory during contango market conditions (when the price of crude oil for future delivery is higher than current prices);
buying and selling crude oil of different grades at different locations in order to maximize value;
transporting crude oil using our pipelines, terminals and trucks or, when necessary or cost effective, pipelines, terminals or trucks owned and operated
by third parties; and
• marketing crude oil to major integrated oil companies, independent refiners and resellers through various types of sale and exchange transactions.
Investment in Sunoco LP
Sunoco LP is primarily engaged in the distribution of motor fuels to independent dealers, distributors, and other commercial customers and the distribution
of motor fuels to end-user customers at retail sites operated by commission agents. Additionally, it receives rental income through the leasing or subleasing
of real estate used in the retail distribution of motor fuel. Sunoco LP also operates 75 retail stores located in Hawaii and New Jersey.
Sunoco LP is a distributor of motor fuels and other petroleum products which Sunoco LP supplies to third-party dealers and distributors, to independent
operators of commission agent locations and other commercial consumers of motor fuel. Also included in the wholesale operations are transmix processing
plants and refined products terminals. Transmix is the mixture of various refined products (primarily gasoline and diesel) created in the supply chain
(primarily in pipelines and terminals) when various products interface with each other. Transmix processing plants separate this mixture and return it to
salable products of gasoline and diesel.
Sunoco LP is the exclusive wholesale supplier of the Sunoco-branded and EcoMaxx-branded motor fuels, supplying an extensive distribution network of
approximately 5,534 company and third-party operated locations throughout the United States and Puerto Rico. In addition to distributing motor fuels,
Sunoco LP also distributes other petroleum products such as propane and lubricating oil, and Sunoco LP receives rental income from real estate that it
leases or subleases.
Investment in USAC
USAC provides natural gas compression services throughout the United States, including the Utica, Marcellus, Permian Basin, Eagle Ford, Mississippi
Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. USAC provides compression services to its customers primarily in
connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline
system and enhancing crude oil production through artificial lift processes. As such, USAC’s compression services play a critical role in the production,
processing and transportation of both natural gas and crude oil. As of December 31, 2023, USAC had 3.8 million horsepower in its fleet.
USAC operates a modern fleet of compression units, with an average age of approximately 11 years. USAC’s standard new-build compression units are
generally configured for multiple compression stages allowing USAC to operate its units across a broad range of operating conditions. As part of USAC’s
services, it engineers, designs, operates, services and repairs its compression units and maintains related support inventory and equipment.
USAC provides compression services to its customers under fixed-fee contracts with initial contract terms typically between six months to five years,
depending on the application and location of the compression unit. USAC typically continues to provide compression services at a specific location beyond
the initial contract term, either through contract renewal or on a month-to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby
its customers are required to pay a monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of its
cash flows. USAC is not directly exposed to commodity price risk because it does not take title to the natural gas or crude oil involved in its services and
because the natural gas used as fuel by its compression units is supplied by its customers without cost to USAC.
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Index to Financial Statements
USAC’s assets and operations are all located and conducted in the United States.
All Other Segment
Our “All Other” segment includes:
•
•
•
•
•
our gas marketing activities, which optimize basis pricing differentials by purchasing and transporting natural gas, primarily on company owned
pipelines, and selling that gas primarily to industrial end-users or to other marketers;
our commodity marketing company, which focuses primarily on wholesale power trading activities;
our natural gas compression equipment business, which has operations in Arkansas, California, Colorado, Louisiana, New Mexico, Oklahoma,
Pennsylvania and Texas;
our wholly owned subsidiary, Dual Drive Technologies, Ltd., which provides compression services to customers engaged in the transportation of
natural gas, including our other segments; and
subsidiaries involved in the management of coal and natural resources properties and the related collection of royalties. We also earn revenues from
other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties.
These operations also include end-user coal handling facilities.
Asset Overview
The following descriptions include summaries of significant assets within the Partnership’s reportable segments. Amounts, such as capacities, volumes and
miles included in the following descriptions are approximate and are based on information currently available; such amounts are subject to change based on
future events or additional information.
The map below depicts the major assets of our core businesses, excluding the assets of Sunoco LP, USAC and the businesses in our all other segment. The
map below and the maps included within the segment asset descriptions include certain non-wholly owned joint ventures and exclude corporate and field
offices and certain assets that are less significant to the Partnership on a consolidated basis.
12
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Index to Financial Statements
Intrastate Transportation and Storage
The following details our pipelines and storage facilities in the intrastate transportation and storage segment:
Description of Assets
(1)
ET Fuel System
(1)
Oasis Pipeline
Houston Pipeline (“HPL”) System
ETC Katy Pipeline
Regency Intrastate Gas System (“RIGS”)
Oklahoma Intrastate Transmission (“OIT”)
Comanche Trail Pipeline
Trans-Pecos Pipeline
Red Bluff Express Pipeline
(1)
(1)
Includes bi-directional capabilities
Miles of Natural
Gas Pipeline
Pipeline
Throughput
Capacity
(Bcf/d)
Working Storage
Capacity
(Bcf)
3,150
750
3,920
460
450
2,200
195
140
120
5.2
2.0
5.3
2.9
2.1
2.4
1.1
1.4
1.4
11.2
—
52.5
—
—
24.0
—
—
—
Ownership Interest
100 %
100 %
100 %
100 %
100 %
100 %
16 %
16 %
70 %
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Index to Financial Statements
The following information describes our principal intrastate transportation and storage assets:
•
•
•
•
The ET Fuel System serves some of the most prolific production areas in the United States and is comprised of intrastate natural gas pipelines and
related natural gas storage facilities. The ET Fuel System has bi-directional capabilities and has many interconnections with pipelines providing direct
access to power plants and other intrastate and interstate pipelines. It is strategically located near high-growth production areas and provides access to
the three major natural gas trading centers in Texas: the Waha Hub near Pecos, Texas, the Maypearl Hub in Central Texas and the Carthage Hub in East
Texas.
The ET Fuel System also includes our Bethel natural gas storage facility, with a working capacity of 6.0 Bcf, an average withdrawal capacity of 300
MMcf/d and an injection capacity of 75 MMcf/d, and our Bryson natural gas storage facility, with a working capacity of 5.2 Bcf, an average
withdrawal capacity of 120 MMcf/d and an average injection capacity of 96 MMcf/d.
In addition, the ET Fuel System is integrated with our Godley processing plant which gives us the ability to bypass the plant when processing margins
are unfavorable by blending the untreated natural gas from our gas gathering system known as the North Texas System with natural gas on the ET Fuel
System while continuing to meet pipeline quality specifications.
The Oasis Pipeline is primarily a 36-inch natural gas pipeline. It has bi-directional capabilities with approximately 1.3 Bcf/d of throughput capacity
moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis Pipeline connects to the Waha and Katy
market hubs and has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
The Oasis Pipeline is integrated with our gathering system known as the Southeast Texas System and is an important component to maximizing our
Southeast Texas System’s profitability. The Oasis Pipeline enhances the Southeast Texas System by (i) providing access for natural gas gathered on the
Southeast Texas System to third-party supply and market points and interconnecting pipelines and (ii) allowing us to bypass our processing plants and
treating facilities on the Southeast Texas System when processing margins are unfavorable by blending untreated natural gas from the Southeast Texas
System with gas on the Oasis pipeline while continuing to meet pipeline quality specifications.
The HPL System is an extensive network of intrastate natural gas pipelines, the underground Bammel storage reservoir and related transportation
assets. The system has access to multiple sources of historically significant natural gas supply reserves from South Texas, the Gulf Coast of Texas, East
Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus
Christi, Texas City, Beaumont and other cities located along the Gulf Coast of Texas. The HPL System is well situated to gather and transport gas in
many of the major gas producing areas in Texas including a strong presence in the key Houston Ship Channel and Katy Hub markets, allowing us to
play an important role in the Texas natural gas markets. The HPL System also offers its shippers off-system opportunities due to its numerous
interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel, Carthage and Agua Dulce as
well as our Bammel storage facility.
The Bammel storage facility has a total working gas capacity of approximately 52.5 Bcf, a peak withdrawal rate of 1.3 Bcf/d and a peak injection rate
of 0.6 Bcf/d. The Bammel storage facility is located near the Houston Ship Channel market area and the Katy Hub, and is ideally suited to provide a
physical backup for on-system and off-system customers. As of December 31, 2023, we had approximately 17.2 Bcf committed under fee-based
arrangements with third parties and approximately 37.0 Bcf stored in the facility for our own account.
The ETC Katy Pipeline connects three treating facilities, one of which we own, with our gathering system known as Southeast Texas System. The ETC
Katy Pipeline serves producers in East and North Central Texas and provides access to the Katy Hub. The ETC Katy Pipeline expansions include the
36-inch East Texas extension to connect our Reed compressor station in Freestone County to our Grimes County compressor station, the 36-inch Katy
expansion connecting Grimes to the Katy Hub and the 42-inch Southeast Bossier pipeline connecting our Cleburne to Carthage pipeline to the HPL
System.
•
RIGS is a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets.
• OIT is a 2,200-mile pipeline system that provides natural gas transportation and storage services to customers in Oklahoma. OIT is a web-like
configuration with multidirectional flow capabilities between numerous receipt points and delivery points. OIT delivers natural gas from the Anadarko
and Arkoma basins, including the SCOOP, STACK, Cana Woodford, Granite Wash, Cleveland, Tonkawa and Mississippi Lime Shale plays in western
Oklahoma to utilities and industrial end-users connected to OIT and to interstate and intrastate pipelines interconnected with OIT. OIT also has two
underground natural gas storage facilities in Oklahoma, which operate at a combined capacity of 24 Bcf with a peak withdrawal rate of 0.60 Bcf/d.
14
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Index to Financial Statements
•
•
•
Comanche Trail Pipeline is a 195-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico
border near San Elizario, Texas. The Partnership owns a 16% membership interest in and operates Comanche Trail Pipeline.
Trans-Pecos Pipeline is a 143-mile intrastate pipeline that delivers natural gas from the Waha Hub near Pecos, Texas to the United States/Mexico
border near Presidio, Texas. The Partnership owns a 16% membership interest in and operates Trans-Pecos Pipeline.
The Red Bluff Express Pipeline is an approximately 120-mile intrastate pipeline that runs through the heart of the Delaware Basin and connects certain
of our plants as well as third-party plants to the Waha Oasis Header. The Partnership owns a 70% membership interest in and operates Red Bluff
Express Pipeline.
• Other intrastate natural gas pipelines include our 630-mile Pelico Pipeline in northern Louisiana and our 167-mile Lobo Pipeline in South Texas.
Interstate Transportation and Storage
The following details our pipelines in the interstate transportation and storage segment:
Description of Assets
(1)
Florida Gas Transmission (“FGT”)
Transwestern Pipeline
Panhandle Eastern Pipe Line
Trunkline
Tiger
Fayetteville Express Pipeline
Sea Robin Pipeline
Stingray Pipeline
Rover Pipeline
Midcontinent Express Pipeline
Miles of Natural
Gas Pipeline
Pipeline
Throughput
Capacity
(Bcf/d)
Working Storage
Capacity
(Bcf)
5,380
2,590
6,300
2,190
200
185
765
335
720
510
4.0
2.1
2.8
0.9
2.4
2.0
2.0
0.4
3.4
1.8
—
—
73.0
13.0
—
—
—
—
—
—
Ownership Interest
50 %
100 %
100 %
100 %
100 %
50 %
100 %
100 %
32.6 %
50 %
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Index to Financial Statements
Enable Gas Transmission (“EGT”)
Mississippi River Transmission (“MRT”)
Southeast Supply Header (“SESH”)
Gulf Run Pipeline
100 %
100 %
50 %
100 %
5,700
1,675
290
335
4.8
1.7
1.1
3.0
29.3
48.9
—
—
(1)
Storage capacity figure includes storage leased from Southwest Gas and third-party companies.
The following information describes our principal interstate transportation and storage assets:
•
•
•
•
•
•
•
•
•
FGT extends from South Texas through the Gulf Coast region of the United States to South Florida. FGT is the principal transporter of natural gas to
the Florida energy market, delivering approximately 60% of the natural gas consumed in the state. In addition, FGT’s numerous intrastate and
interstate pipeline interconnections with major interstate and intrastate natural gas pipelines provide access to diverse natural gas supply sources.
FGT’s customers include electric utilities, independent power producers, industrial end-users and local distribution companies. FGT is owned by
Citrus, a 50/50 joint venture with Kinder Morgan, Inc.
Transwestern Pipeline transports natural gas supply from the Permian Basin, the San Juan Basin and the Anadarko Basin. The system has bi-
directional capabilities and can access Texas and Midcontinent natural gas market hubs as well as major western markets in Arizona, Nevada and
California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.
Panhandle Eastern Pipe Line’s transmission system consists of four large diameter mainline pipelines with bi-directional capabilities, extending
approximately 1,300 miles from producing areas in the Anadarko Basin of Texas, Oklahoma and Kansas through Missouri, Illinois, Indiana, Ohio and
into Michigan. Panhandle contracts for over 73 Bcf of natural gas storage.
Trunkline’s transmission system consists of one large diameter mainline pipeline with bi-directional capabilities, extending approximately 1,400 miles
from the Gulf Coast areas of Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, Indiana and Michigan. Trunkline has
one natural gas storage field located in Louisiana.
Tiger is a bi-directional system that extends through the heart of the Haynesville Shale and ends near Delhi, Louisiana, interconnecting with multiple
interstate pipelines.
Fayetteville Express Pipeline originates near Conway County, Arkansas and continues eastward to Panola County, Mississippi with multiple pipeline
interconnections along the route. Fayetteville Express Pipeline is owned by a 50/50 joint venture with Kinder Morgan, Inc.
Sea Robin Pipeline’s system consists of two offshore Louisiana natural gas supply pipelines extending 120 miles into the Gulf of Mexico.
Stingray Pipeline is an interstate natural gas pipeline system with assets located in the western Gulf of Mexico and Johnson Bayou, Louisiana.
Rover Pipeline is a large diameter pipeline which transports natural gas from processing plants in West Virginia, eastern Ohio and western
Pennsylvania for delivery to other pipeline interconnects in Ohio and Michigan, where the gas is delivered for distribution to markets across the United
States and to Ontario, Canada.
• Midcontinent Express Pipeline originates near Bennington, Oklahoma and traverses northern Louisiana and central Mississippi to an interconnect with
the Transcontinental Gas Pipeline system in Butler, Alabama. The Midcontinent Express Pipeline is owned by a 50/50 joint venture with Kinder
Morgan, Inc., the operator of the system.
•
EGT provides natural gas transportation and storage services to customers in Oklahoma, Texas, Arkansas, Louisiana, Missouri and Kansas. EGT has
two underground storage facilities in Oklahoma and one underground natural gas storage facility in Louisiana. Through numerous pipeline
interconnections along the system and at the Perryville Hub, EGT customers have access to Midwest and Northeast markets as well as most of the
major natural gas consuming markets east of the Mississippi River.
• MRT provides natural gas transportation and storage services in Texas, Arkansas, Louisiana, Missouri and Illinois. MRT has underground natural gas
storage facilities in Louisiana and Illinois. MRT receives natural gas from a variety of interstate and intrastate pipelines through its interconnections
and delivers natural gas primarily to the St. Louis market.
•
SESH, a 50/50 joint venture with Enbridge Inc., provides transportation services in Louisiana, Mississippi and Alabama. SESH transports natural gas
from the Perryville Hub in Louisiana to its endpoint in Mobile County, Alabama. SESH has interconnections with third party natural gas pipelines and
provides access to major Southeast and Northeast markets and
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Index to Financial Statements
transports directly to generating facilities in Mississippi and Alabama and to interconnecting pipelines that supply companies generating electricity for
the Florida power market.
• Gulf Run Pipeline is a large diameter pipeline that runs from the heart of the Haynesville Shale in East Texas and northern Louisiana to the Carthage
and Perryville natural gas hubs and other key markets along the Gulf Coast.
Regasification Facility
Lake Charles LNG, our wholly owned subsidiary, owns an LNG import terminal and regasification facility located on Louisiana’s Gulf Coast near Lake
Charles, Louisiana. The import terminal has approximately 9.0 Bcf of above ground LNG storage capacity and the regasification facility has a send out
capacity of 1.8 Bcf/d. Lake Charles LNG derives all of its revenue from a series of long-term contracts with a wholly owned subsidiary of Royal Dutch
Shell plc (“Shell”).
Liquefaction Project
Lake Charles LNG Export, our wholly owned subsidiary, is developing a natural gas liquefaction project at the site of our Lake Charles LNG import
terminal and regasification facility. The project would utilize existing dock and storage facilities owned by Lake Charles LNG located on the Lake Charles
site. Lake Charles LNG Export entered into a prior development agreement with Shell in March 2019; however, Shell withdrew from the project in March
2020 due to adverse market factors affecting Shell’s business following the onset of the COVID-19 pandemic. The project will benefit from the
infrastructure related to the existing regasification facility at the same site, including four LNG storage tanks, two deep water docks and other assets. The
construction of the liquefaction facility has been approved by FERC. In addition, Lake Charles LNG Export received its wetlands permits from the USACE
to perform wetlands mitigation work and to perform modification and dredging work for the temporary and permanent dock facilities at the Lake Charles
LNG facilities.
The export of LNG produced by any liquefaction facility in the United States requires export authorization from the DOE. The NGA requires the DOE to
approve applications for LNG exports unless such approval would be “inconsistent with the public interest.” In March 2013, Lake Charles LNG Export
obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in
natural gas (the “FTA Authorization”). In July 2016, Lake Charles LNG Export also obtained a conditional DOE authorization to export LNG to countries
that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”) subject to commencement of exports no later than December 2020. Lake
Charles LNG Export applied for an extension of the deadline to commence exports under the Non-FTA Authorization to December 2025 and the DOE
approved such extension request in October 2020. Lake Charles LNG Export applied for a second extension of the deadline to commence exports and in
April 2023 the DOE denied this request in connection with a new DOE policy related to extension requests. In light of this new policy, in August 2023,
Lake Charles LNG Export applied for a new Non-FTA Authorization which, if approved, would provide for a new deadline to commence exports to Non-
FTA countries, which deadline would be seven years from the date of such approval. In January 2024, the Biden administration announced a moratorium
on the approval of LNG export authorizations by the DOE and instructed the DOE to conduct studies related to the cumulative impact of LNG exports on
domestic natural gas prices, climate change and other matters. The Biden administration stated that these studies were necessary to enable the DOE to make
determinations related to the statutory “public interest” standard. The DOE has stated that these studies will take several months to complete, after which a
draft policy statement will be made available for public comment prior to finalizing the policy statement. This process is not expected to be completed prior
to the U.S. Presidential election in November 2024.
During 2022, Lake Charles LNG Export executed six LNG offtake agreements, for an aggregate of nearly 8 million tonnes per annum, including a 20-year
LNG agreement with Shell NA LNG LLC. The agreements allow either party to terminate the agreement if Lake Charles LNG Export has not satisfied
specified conditions by a specified date. One of those conditions relates to Lake Charles LNG Export making a “final investment decision” to proceed with
the construction of the liquefaction facility. To date, the specified dates for satisfying these conditions have been extended by mutual agreement of the
parties to the agreements. We have also signed nonbinding letter agreements with several customers for LNG offtake, and we are in discussions with
several parties for potential long-term LNG offtake and potential equity investments in the project.
During the moratorium imposed by the Biden administration on the approvals of LNG export authorizations by the DOE, Lake Charles LNG Export
intends to continue to engage with existing and prospective LNG offtake customers and potential equity investors in the project.
17
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Index to Financial Statements
Midstream
The following details our assets in the midstream segment:
Description of Assets
South Texas
Ark-La-Tex
North Central Texas
Permian Basin
Midcontinent
Williston Basin
Powder River Basin
Eastern
Net Gas
Processing
Capacity
(MMcf/d)
2,430
922
700
3,428
2,925
430
345
200
The following information describes our principal midstream assets:
South Texas:
• Our South Texas assets, which include the Southeast Texas System and the Eagle Ford System, are an integrated system that gathers, compresses,
treats, processes, dehydrates and transports natural gas from the Austin Chalk trend and the Eagle Ford Shale.
The assets in our Southeast Texas System include a large natural gas gathering system that covers thirteen counties between Austin and Houston, Texas
and connects to the Katy Hub through the ETC Katy Pipeline and is also connected to the Oasis Pipeline. This system also includes three natural gas
processing plants (La Grange, Alamo and Brookeland) with
18
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Index to Financial Statements
an aggregate capacity of 510 MMcf/d. These plants process the rich gas that flows through our gathering system to produce residue gas and NGLs.
Residue gas is delivered into our intrastate pipelines and NGLs are delivered into our NGL pipelines.
Our treating facilities remove carbon dioxide and hydrogen sulfide from natural gas gathered into our system before the natural gas is introduced to
transportation pipelines to ensure that the gas meets pipeline quality specifications.
The assets in our Eagle Ford System consist of 30-inch and 42-inch natural gas gathering pipelines originating in Dimmitt County, Texas, and
extending to both our King Ranch gas plant in Kleberg County, Texas and Jackson plant in Jackson County, Texas. These assets also include four
processing plants (Chisholm, Kenedy, Jackson and King Ranch) with an aggregate capacity of 1.9 Bcf/d. Our Chisholm, Kenedy, Jackson and King
Ranch processing plants are connected to our intrastate transportation pipeline systems for deliveries of residue gas and are also connected with our
NGL pipelines.
• We own a 60% interest in Edwards Lime Gathering, LLC, which operates natural gas gathering, compression and treating facilities as well as an oil
pipeline and oil stabilization facility in South Texas.
Ark-La-Tex:
• Our Ark-La-Tex assets are comprised of several gathering systems in the Haynesville Shale with access to multiple markets through interconnects with
several pipelines, including our Tiger pipeline. Our northern Louisiana assets include the Bistineau, Creedence, Tristate, Logansport, Magnolia,
Olympia, Amoruso, and Lumberjack systems, which collectively include 11 natural gas treating facilities, with aggregate capacity of 3.1 Bcf/d.
The Ark-La-Tex assets gather, compress, treat and dehydrate natural gas in several parishes in northwest Louisiana and several counties in East Texas.
These assets also include cryogenic natural gas processing facilities, a refrigeration plant, a conditioning plant, amine treating plants, a residue gas
pipeline that provides market access for natural gas from our processing plants, including connections with pipelines that provide access to the
Perryville Hub and other markets in the Gulf Coast region, and an NGL pipeline that connects to a third party that provides access to the Mont Belvieu
market for NGLs produced from our processing plants. Collectively, the six natural gas processing facilities (Dubach, Lincoln, Rosewood, Mt. Olive,
Sligo and Waskom) have an aggregate capacity of 0.9 Bcf/d.
Through the gathering and processing systems described above and their interconnections with our intrastate transportation pipelines, we offer
producers wellhead-to-market services, including natural gas gathering, compression, processing, treating and transportation.
North Central Texas:
•
The North Central Texas System is an integrated system located in four counties in North Central Texas that gathers, compresses, treats, processes and
transports natural gas from the Barnett and Woodford shales. Our North Central Texas assets include our Godley plant, which processes rich gas
produced from the Barnett Shale and STACK play, with an aggregate capacity of 700 MMcf/d. The Godley plant is integrated with the ET Fuel
System.
Permian Basin:
•
•
The Permian Basin Gathering System offers wellhead-to-market services to producers in 11 counties in West Texas and two counties in New Mexico
which surround the Waha Hub, one of Texas’s developing NGL-rich natural gas market areas. As a result of the proximity of our system to the Waha
Hub, the Waha Gathering System has a variety of market outlets for the natural gas that we gather and process, including several major interstate and
intrastate pipelines serving California, the Midcontinent and Texas natural gas markets. The NGL market outlets includes our NGL pipeline system.
The Permian Basin Gathering System includes 13 processing facilities (Waha, Red Bluff, Halley, Keystone, Tippet, Panther, Rebel, Grey Wolf, Bear,
Arrowhead, Carlsbad, Orla I and Orla II) with an aggregate processing capacity of 3.2 Bcf/d and one natural gas conditioning facility with an
aggregate capacity of 200 MMcf/d.
In addition, we own a 50% membership interest in Mi Vida JV LLC, a joint venture which owns a 200 MMcf/d cryogenic processing plant in West
Texas. We operate the plant and related facilities on behalf of the joint venture. We also own a 50% equity interest in Crestwood Permian Basin LLC, a
joint venture which owns the Nautilus natural gas gathering system in West Texas. We operate the gathering system on behalf of the joint venture.
Midcontinent:
•
The Midcontinent Systems are located in three large natural gas producing regions in the United States: the Hugoton Basin in southwest Kansas, the
Anadarko Basin in the Texas Panhandle and Oklahoma, including the STACK and SCOOP plays, and the Arkoma Basin in eastern Oklahoma and
Arkansas. These mature basins have continued to provide generally long-lived, predictable production volumes. Our Midcontinent assets are extensive
systems that gather, compress and dehydrate low-pressure gas. The Midcontinent Systems include 17 natural gas processing facilities (Mocane,
Beaver, Wheeler I,
19
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Index to Financial Statements
Sunray, Spearman, Rose Valley, Hopeton, Bradley, McClure, Wheeler II, South Canadian, Clinton, Roger Mills, Canute, Cox City, Wetumka and
Grady) with an aggregate capacity of approximately 2.9 Bcf/d.
• We operate our Midcontinent Systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are
therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.
• We own the Hugoton Gathering System that has 1,900 miles of pipeline extending across parts of southwest Kansas and northwest Oklahoma. This
system is operated by a third party.
• We own a 50% membership interest in Atoka Midstream LLC, which owns a natural gas gathering system in Oklahoma.
Williston Basin:
• We own and operate the Arrow and Rough Rider systems which include natural gas gathering systems and processing facilities (Bear Den and Wild
Basin). These processing facilities have an aggregate capacity of 430 MMcf/d. The Arrow and Rough Rider systems are in the core of the Bakken
Shale primarily in McKenzie and Dunn Counties, North Dakota, with the Arrow system primarily located on the Fort Berthold Indian Reservation.
Powder River Basin:
• We own and operate the Jackalope rich natural gas gathering system, the Continental Express high-pressure pipeline and the Bucking Horse gas
processing facility in Converse County, Wyoming. The Bucking Horse gas processing facility has an aggregate processing capacity of 345 MMcf/d.
Eastern:
•
The Eastern region assets are located in eleven counties in Pennsylvania, four counties in Ohio and three counties in West Virginia, which gather
natural gas from the Marcellus and Utica shales. Our Eastern region assets include approximately 600 miles of natural gas gathering pipelines, natural
gas trunklines and fresh-water pipelines, nine gathering and processing systems and the 200 MMcf/d Revolution processing plant, which feeds into our
Mariner East and Rover pipeline systems.
• We also own a 51% membership interest in Aqua – ETC Water Solutions LLC, a joint venture that transports and supplies fresh water to natural gas
producers drilling in the Marcellus Shale in Pennsylvania.
• We own a 75% membership interest in ORS. On behalf of ORS, we operate its Ohio Utica River System, which consists of 47 miles of 36-inch, 13
miles of 30-inch and 3 miles of 24-inch gathering trunklines, and which delivers up to 3.6 Bcf/d to Rockies Express Pipeline, Texas Eastern
Transmission, Leach Xpress, Rover and DEO TPL-18.
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Index to Financial Statements
NGL and Refined Products Transportation and Services
The following details the assets in our NGL and refined products transportation and services segment:
Description of Assets
Miles of Liquids
Pipeline
NGL Fractionation
/ Processing
Capacity
(MBbls/d)
Working Storage
Capacity
(MBbls)
Liquids Pipelines:
Gulf Coast NGL Express
West Texas Gateway
Other Permian Basin NGL
Mariner East
Mariner West
Mont Belvieu to Nederland
(1)
White Cliffs
Other NGL
Liquids Fractionation and Storage Facilities:
Mont Belvieu NGL Complex
Spindletop
Crestwood
ET Geismar Olefins
Hattiesburg
Cedar Bayou
(2)
900
510
1,600
680
450
270
540
750
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,150
—
—
35
—
—
—
—
—
—
—
—
—
—
60,000
8,000
10,000
—
5,200
1,600
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Index to Financial Statements
NGL Terminals:
Nederland
Orbit Gulf Coast
Marcus Hook
Inkster
Refined Products Pipelines:
Eastern region
Midcontinent region
Southwest region
Inland
J.C. Nolan Pipeline
Refined Products Terminals:
Eagle Point
Marcus Hook Terminal
Marcus Hook Tank Farm
Marketing Terminals
J.C. Nolan Terminal
—
—
—
—
1,580
480
590
610
500
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,900
1,200
6,000
860
—
—
—
—
—
6,700
930
1,900
7,700
130
(1)
(2)
The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
Additionally, the ET Geismar Olefins off-gas processing facility has inlet volume capacity of 54 MMcf/d.
The following information describes our principal NGL and refined products transportation and services assets:
• Gulf Coast NGL Express is an interstate NGL pipeline consisting of 24-inch and 30-inch long-haul transportation pipelines, with throughput capacity
of approximately 900 MBbls/d, that delivers mixed NGLs from processing plants in the Permian Basin, the Barnett Shale and from East Texas to our
Mont Belvieu NGL Complex.
• West Texas Gateway transports mixed NGLs produced in the Permian Basin and the Eagle Ford Shale to Mont Belvieu, Texas and has a throughput
capacity of approximately 240 MBbls/d.
•
•
•
•
The Mariner East Pipeline System, consisting of Mariner East 2 and Mariner East 2x, has an aggregate capacity of 350 to 375 MBbls/d and transports
NGLs from the Marcellus and Utica shales in western Pennsylvania, West Virginia and eastern Ohio to destinations in Pennsylvania, including our
Marcus Hook Terminal on the Delaware River, where they are processed, stored and distributed to local, domestic and waterborne markets.
The Mariner West Pipeline provides transportation of ethane from the Marcellus Shale processing and fractionating areas in Houston, Pennsylvania to
Marysville, Michigan and the Canadian border and has a throughput capacity of approximately 50 MBbls/d.
The Mont Belvieu to Nederland Pipeline System consists of four pipelines, which deliver export-grade propane, butane, ethane and natural gasoline
from our Mont Belvieu NGL Complex to our Nederland Terminal, having a total throughput capacity of approximately 730 MBbls/d. The ethane
pipeline is part of the Orbit Gulf Coast joint venture, as described below.
The White Cliffs NGL pipeline, in which we have 51% ownership interest, transports mixed NGLs produced in the DJ Basin to Cushing, Oklahoma
where it interconnects with the Southern Hills Pipeline to move NGLs to Mont Belvieu, Texas and has a throughput capacity of approximately 90
MBbls/d.
• Other NGL pipelines include the 127-mile Justice pipeline, 63-mile Blue Ridge pipeline, the 45-mile Freedom pipeline, the 20-mile Spirit pipeline and
a 50% interest in the 87 mile Liberty pipeline. Through our recent acquisition of Crestwood, we also own an undivided interest in 80 MBbls/d of
capacity in a segment of the EPIC Y-Grade Pipeline, LP (EPIC) pipeline from Orla, Texas to Benedum, Texas.
• Our Mont Belvieu NGL Complex is an integrated liquids storage and fractionation facility. The storage facility has approximately 60 MMBbls of salt
dome capacity providing 100% fee-based cash flows. The storage facility has access to multiple NGL and refined products pipelines, the Houston Ship
Channel trading hub, numerous chemical plants, refineries and fractionators.
22
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Index to Financial Statements
The fractionation facility includes eight fractionators, which process NGLs delivered from several sources, including our Gulf Coast NGL Express,
West Texas Gateway and Justice pipelines.
• Our Spindletop storage facilities, located in Beaumont, Texas, have 8 MMBbls of salt dome capacity.
• Acquired in 2023, Crestwood’s NGL storage assets include 13 LPG terminals which offer 10 MMBbls of storage capacity located in Pennsylvania,
South Carolina, Mississippi, Michigan, New York and Indiana, with receipts and deliveries that are supported by both rail cars and third-party
pipelines.
Other Crestwood assets include a fleet of rail and rolling stock with approximately 1.6 MMBbls/d of NGL pipeline, terminal and transportation
capacity, which also includes rail-to-truck terminals located in Michigan, Indiana, Ohio, New Hampshire, Pennsylvania, New Jersey, New York, Rhode
Island, North Carolina, South Carolina and Mississippi.
ET Geismar Olefins consists of a refinery off-gas processing unit and an o-grade NGL fractionation / Refinery-Grade Propylene (“RGP”) splitting
complex located along the Mississippi River refinery corridor in southern Louisiana. The off-gas processing unit cryogenically processes refinery off-
gas, and the fractionation / RGP splitting complex fractionates the streams into higher value components. The o-grade fractionator and RGP splitting
complex, located in Geismar, Louisiana, is connected by approximately 100 miles of pipeline to the Chalmette processing plant, which has a
processing capacity of 54 MMcf/d.
The Hattiesburg storage facility is an integrated liquids storage facility with approximately 5 MMBbls of salt dome capacity, providing 100% fee-
based cash flows.
The Cedar Bayou storage facility is an integrated liquids storage facility with approximately 1.6 MMBbls of tank storage, generating revenues from
fixed fee storage contracts, throughput fees and revenue from blending butane into refined gasoline.
The Nederland Terminal, in addition to crude oil activities, also provides approximately 1.9 MMBbls of storage and distribution services for NGLs
delivered from our Mont Belvieu NGL Complex via our Mont Belvieu to Nederland Pipeline System, where such products can be exported via ship.
The Orbit Gulf Coast joint venture consists of a 70-mile, 20-inch ethane pipeline with a throughput capacity of approximately 200 MBbls/d which
delivers from our Mont Belvieu NGL Complex to our Nederland Terminal. It also includes a 180 MBbls/d ethane refrigeration facility and a 1.2
MMBbls storage facility at our Nederland Terminal.
The Marcus Hook Terminal includes fractionation, terminalling and storage assets with a capacity of approximately 2 MMBbls of NGL storage
capacity in underground caverns, 4 MMBbls of above-ground NGL refrigerated storage and related commercial agreements. The terminal has a total
active refined products storage capacity of approximately 1 MMBbls. The facility can receive NGLs and refined products via marine vessel, pipeline,
truck and rail, and can deliver via marine vessel, pipeline and truck. In addition to providing NGL storage and terminalling services to both affiliates
and third-party customers, the Marcus Hook Terminal serves as an offtake outlet for our Mariner East Pipeline System.
The Marcus Hook Terminal also has a tank farm with total refined products storage capacity of approximately 2 MMBbls. The terminal receives and
delivers refined products via pipeline and primarily provides terminalling services to support movements on our refined products pipelines.
The Inkster Terminal, located near Detroit, Michigan, consists of multiple salt caverns with a total storage capacity of approximately 860 MBbls of
NGLs. We use the Inkster Terminal’s storage in connection with the Toledo North pipeline system and for the storage of NGLs from local producers
and a refinery in western Ohio. The terminal can receive and ship by pipeline in both directions and has a truck loading and unloading rack.
The Eastern region refined products pipelines consist of 6-inch to 16-inch diameter refined product pipelines in eastern, central and north central
Pennsylvania, 8-inch refined products pipeline in western New York and various diameter refined products pipelines in New Jersey (including 80 miles
of the 16-inch diameter Harbor Pipeline).
The Midcontinent region refined products pipelines primarily consist of 3-inch to 12-inch refined products pipelines in Ohio and 6-inch and 8-inch
refined products pipeline in Michigan.
The Southwest region refined products pipelines are located in East Texas and consist primarily of 8-inch and 12-inch diameter refined products
pipeline.
The Inland refined products pipeline consists of 12-, 10-, 8- and 6-inch diameter pipelines in the western, northwestern, and northeastern regions of
Ohio.
The J.C. Nolan Pipeline, a joint venture between a wholly owned subsidiary of the Partnership and a wholly owned subsidiary of Sunoco LP, transports
diesel fuel from a tank farm in Hebert, Texas to Midland, Texas, and has a throughput capacity of approximately 36 MBbls/d.
•
•
•
•
•
•
•
•
•
•
•
•
23
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Index to Financial Statements
• We have 37 refined products terminals with an aggregate storage capacity of approximately 8 MMBbls that facilitate the movement of refined products
to or from storage or transportation systems, such as a pipeline, to other transportation systems, such as trucks or other pipelines. Each facility typically
consists of multiple storage tanks and is equipped with automated truck loading equipment that is operational 24 hours a day.
•
•
•
The Eagle Point Terminal can accommodate three marine vessels (ships or barges) to receive and deliver refined products to outbound ships and
barges. The tank farm has a total active refined products storage capacity of approximately 7 MMBbls and provides customers with access to the
facility via ship, barge, rail and pipeline. The terminal can deliver via ship, barge, rail, truck or pipeline, providing customers with access to various
markets. The terminal generates revenue primarily by charging fees based on throughput, blending services and storage.
The J.C. Nolan Terminal, a joint venture between a wholly owned subsidiary of the Partnership and a wholly owned subsidiary of Sunoco LP, provides
diesel fuel storage in Midland, Texas.
This segment also includes the following joint ventures: a 15% membership interest in Explorer, a 1,850-mile pipeline which originates from refining
centers in Beaumont, Port Arthur and Houston, Texas and extends to Chicago, Illinois; a 31% membership interest in the Wolverine Pipe Line
Company, a 1,055-mile pipeline that originates from Chicago, Illinois and extends to Detroit, Grand Haven, and Bay City, Michigan; a 17%
membership interest in the West Shore Pipe Line Company, a 650-mile pipeline which originates in Chicago, Illinois and extends to Madison and
Green Bay, Wisconsin; a 14% membership interest in the Yellowstone Pipe Line Company, a 710-mile pipeline which originates from Billings,
Montana and extends to Moses Lake, Washington.
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Index to Financial Statements
Crude Oil Transportation and Services
The following details our pipelines and terminals in its crude oil transportation and services operations:
Description of Assets
(1)
Dakota Access Pipeline
Energy Transfer Crude Oil Pipeline
Bayou Bridge Pipeline
West Texas Gulf Pipeline
Permian Express Pipelines
Wattenberg Oil Trunkline
White Cliffs Pipeline
Maurepas Pipeline
Mid Valley Pipeline
Cushing Pipeline
Wink to Webster Pipeline
Other, crude gathering and water gathering and disposal
Nederland Terminal
Midland terminals
Marcus Hook Terminal
Houston Terminal
Cushing Terminal
Patoka Terminal
Ownership Interest
36.40 %
36.40 %
60 %
100.0 %
87.7 %
100 %
51 %
51 %
100 %
100 %
5 %
100 %
100 %
100 %
100 %
100 %
100 %
87.7 %
Miles of Crude
Pipeline
Working Storage
Capacity
(MBbls)
1,170
745
210
584
1,004
75
530
35
1,040
745
642
7,700
—
—
—
—
—
—
—
—
—
—
360
100
—
—
—
—
—
30,000
3,000
1,000
18,200
9,500
1,900
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Index to Financial Statements
Price River Terminal
Colt Hub
55 %
100 %
—
20
200
1,200
(1)
The White Cliffs Pipeline consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one NGL pipeline.
Our crude oil operations consist of an integrated set of pipeline, terminalling, trucking and acquisition and marketing assets that service the movement of
crude oil from producers to end-user markets. The following details our assets in the crude oil transportation and services segment:
Crude Oil Pipelines
Our crude oil pipelines (through wholly owned subsidiaries or joint venture interests) consist of approximately 14,500 miles of crude oil trunk pipelines as
well as crude oil and produced water gathering pipelines throughout the Southwest, Midcontinent and Midwest United States. Our crude oil pipelines
provide access to several trading hubs, including the largest trading hub for crude oil in the United States located in Cushing, Oklahoma, and other trading
hubs located in Midland, Colorado City and Longview, Texas. Our crude oil pipelines also deliver to and connect with other pipelines that deliver crude oil
to a number of refineries.
•
•
Bakken Pipeline. The Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline are collectively referred to as the “Bakken Pipeline.” The
Bakken Pipeline is a 1,915-mile pipeline that transports domestically produced crude oil from the Bakken/Three Forks production areas in North
Dakota to a storage and terminal hub outside of Patoka, Illinois, or to gulf coast connections including our crude terminal in Nederland, Texas. The
Bakken Pipeline has a capacity of up to 750 MBbls/d. The pipeline transports light, sweet crude oil from North Dakota to major refining markets in the
Midwest and Gulf Coast regions.
The Dakota Access Pipeline consists of approximately 1,170 miles of 12, 20, 24 and 30-inch diameter pipeline traversing North Dakota, South Dakota,
Iowa and Illinois. Crude oil transported on the Dakota Access Pipeline originates at six terminal locations in the North Dakota counties of Mountrail,
Williams and McKenzie. The pipeline delivers the crude oil to a hub outside of Patoka, Illinois where it can be delivered to the Energy Transfer Crude
Oil Pipeline for delivery to the Gulf Coast or can be transported via other pipelines to refining markets throughout the Midwest.
The Energy Transfer Crude Oil Pipeline consists of approximately 745 miles of mostly 30-inch diameter pipeline from Patoka, Illinois to Nederland,
Texas, where the crude oil can be refined or further transported to additional refining markets.
Bayou Bridge Pipeline. The Bayou Bridge Pipeline is a joint venture between Energy Transfer and a subsidiary of Phillips 66, in which we have a 60%
ownership interest and serve as the operator of the pipeline. The Bayou Bridge Pipeline consists of a 30-inch pipeline from Nederland, Texas to Lake
Charles, Louisiana, and a 24-inch pipeline from Lake Charles, Louisiana to St. James, Louisiana. Bayou Bridge Pipeline has a capacity of
approximately 480 MBbls/d of light and heavy crude oil from different sources to the St. James crude oil hub, which is home to important refineries
located in the Gulf Coast region.
• West Texas Gulf Pipeline. West Texas Gulf Pipeline is a 26-inch and 20-inch pipeline system that transports barrels from Colorado City, Texas to
Longview, Texas for delivery onto Mid Valley Pipeline and additional delivery points along the Gulf Coast via joint tariff.
•
Permian Express Pipelines. The Permian Express pipelines are part of the PEP joint venture and include the Permian Express 1, Permian Express 2,
Permian Express 3, Permian Express 4, Permian Longview and Louisiana Access, Longview to Louisiana and Nederland Access pipelines. These
pipelines are comprised of crude oil trunk pipelines and crude oil gathering pipelines in Texas and Oklahoma and provide takeaway capacity from the
Permian Basin, with origins in multiple locations in West Texas.
• White Cliffs Pipeline. White Cliffs Pipeline owns a 12-inch common carrier, crude oil pipeline, with a throughput capacity of 100 MBbls/d, that
transports crude oil from Platteville, Colorado to Cushing, Oklahoma.
• Maurepas Pipeline. The Maurepas Pipeline consists of three pipelines, with an aggregate throughput capacity of 460 MBbls/d, which service refineries
in the Gulf Coast region.
• Mid Valley Pipeline. The Mid Valley Pipeline originates in Longview, Texas and passes through Louisiana, Arkansas, Mississippi, Tennessee,
Kentucky and Ohio and terminates in Samaria, Michigan. This pipeline provides crude oil to a number of refineries, primarily in the Midwest United
States.
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Index to Financial Statements
•
Cushing Pipeline. The Cushing Pipeline, acquired as a part of the 2023 Lotus Midstream transaction, consists of two 16-inch crude oil pipelines,
providing service from the Permian Basin to Cushing, Oklahoma and to third-party systems in North Texas.
• Wink to Webster Pipeline. The Wink to Webster Pipeline is capable of transporting approximately 1,000 MBbl/d from origin points at Wink and
Midland in the Permian Basin for delivery to multiple Houston area locations. Our 5% ownership interest in the Wink to Webster Pipeline was
obtained in the 2023 acquisition of Lotus Midstream.
•
Crude Gathering and Water Gathering and Disposal. We own integrated crude oil and water gathering systems across multiple basins in the United
States.
▪
Permian Basin: Our Permian Basin gathering assets in West Texas and eastern New Mexico encompass multiple systems in highly active
areas of both the Delaware and Midland basins, with the ability to deliver virtually all gathered crude to major market hubs, including
Midland, Wink and Crane, as well as our own long-haul pipelines that provide service to the Gulf Coast and Cushing. Our Permian Basin
operations also consist of produced water gathering and disposal services in the Delaware Basin which were acquired in the Crestwood
transaction in the fourth quarter of 2023.
▪ Williston Basin: Our Williston Basin gathering assets in North Dakota and eastern Montana include several systems, acquired through the
Enable and Crestwood acquisitions, built for gathering and transporting crude production from the wellhead to long-haul pipelines, including
our Bakken Pipeline. Additionally, we have multiple water gathering systems in the Williston Basin that transport produced water to wholly
owned and third-party disposal wells.
▪ Midcontinent: Our Midcontinent gathering assets in Oklahoma and Kansas primarily transport wellhead and truck-delivered volumes to
several local refineries as well as to Cushing, Oklahoma. A portion of these operations are conducted through Enable South Central Pipeline,
a joint venture with a subsidiary of CVR Energy, Inc., which is operated by us and in which we own a 60% membership interest.
Crude Oil Terminals
•
Nederland, TX. The Nederland Terminal, located on the Sabine-Neches waterway between Beaumont and Port Arthur, Texas, is a large marine
terminal providing storage and distribution services for refiners and other large transporters of crude oil and NGLs. The terminal receives, stores and
distributes crude oil, NGLs, feedstocks, petrochemicals and bunker oils (used for fueling ships and other marine vessels). The terminal currently has a
total storage capacity of approximately 30 MMBbls in more than 80 above ground storage tanks with individual capacities of up to 660 MBbls.
The Nederland Terminal can receive crude oil at three of its six ship docks and three of its four barge berths. The three ship docks are capable of
receiving over 2 MMBbls/d of crude oil. In addition to our crude oil pipelines, the terminal can also receive crude oil through a number of other
pipelines, including the DOE. The DOE pipelines connect the terminal to the United States Strategic Petroleum Reserve’s West Hackberry caverns at
Hackberry, Louisiana and Big Hill caverns near Winnie, Texas, which have an aggregate storage capacity of approximately 395 MMBbls. The terminal
also has crude oil rail unloading facilities, including steam availability for heating heavy oils prior to loading.
The Nederland Terminal can deliver crude oil and other petroleum products via pipeline, barge and ship. The terminal has three ship docks and three
barge berths that are capable of delivering crude oils for international transport. In total, the terminal is capable of delivering over 2 MMBbls/d of
crude oil to our crude oil pipelines or a number of third-party pipelines including the DOE. The Nederland Terminal generates crude oil revenues
primarily by providing term or spot storage services and throughput capabilities to a number of customers.
• Midland, TX. We have two terminals in Midland, Texas, one of which includes approximately 1 MMBbls of crude oil storage and a combined 20 lanes
of truck loading and unloading; the terminal provides access to the Permian Express pipelines. The second terminal, obtained in the 2023 acquisition of
Lotus Midstream, offers 2 MMBbls of crude oil storage capacity and additional supply and demand connectivity.
• Marcus Hook, PA. The Marcus Hook Terminal can receive crude oil via marine vessel and can deliver via marine vessel and pipeline. The terminal has
a total active crude oil storage capacity of approximately 1 MMBbls.
• Houston, TX. The Houston Terminal consists of storage tanks located on the Houston Ship Channel with an aggregate storage capacity of 18.2
MMBbls used to store, blend and transport refinery products and refinery feedstocks via pipeline, barge, rail, truck and ship. This facility has five
deep-water ship docks on the Houston Ship Channel capable of loading and unloading Suezmax cargo vessels, and seven barge docks that can
accommodate 23 barges simultaneously, three inbound crude oil pipelines, two outbound crude oil pipelines connecting to three refineries, and
numerous rail and truck loading spots.
27
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Index to Financial Statements
•
•
•
•
Cushing, OK. The Cushing Terminal has approximately 9.5 MMBbls of crude oil storage. The storage terminal has inbound connections with the
White Cliffs Pipeline from Platteville, Colorado, the Great Salt Plains Pipeline from Cherokee, Oklahoma, the Cimarron Pipeline from Boyer, Kansas
and two-way connections with all of the other major storage terminals in Cushing. The Cushing Terminal also includes truck unloading facilities.
Patoka, IL. The Patoka Terminal is a tank farm owned by the PEP joint venture and is located in Marion County, Illinois. The facility includes 234
acres of owned land and provides for approximately 1.9 MMBbls of crude oil storage.
Price River Terminal. The Price River Terminal is a rail terminal joint venture in Carbon County, Utah, capable of transloading local waxy crude
production as well as other bulk materials. The terminal has 200 MBbls of heated storage and more than 60 MBbls/d of rail loading capacity.
Colt Hub. The Colt Hub is located in the heart of the Williston Basin in Williams County, North Dakota. Acquired in 2023 as part of the Crestwood
acquisition, the Colt Hub has approximately 1.2 MMBbls of crude oil storage capacity and 160 MBbls/d of rail loading capacity.
Crude Oil Acquisition and Marketing
Our crude oil acquisition and marketing operations are conducted using our assets, which include approximately 378 crude oil transport trucks, 350 trailers,
approximately 176 crude oil truck unloading facilities as well as third-party truck, rail, pipeline and marine assets.
Investment in Sunoco LP
Sunoco LP’s fuel distribution and marketing operations are conducted by the following consolidated subsidiaries:
• Sunoco, LLC (“Sunoco LLC”), a Delaware limited liability company, primarily distributes motor fuel in more than 40 states throughout the United
States. Sunoco LLC also processes transmix and distributes refined product through its terminals in over 15 states.
•
Sunoco Retail LLC (“Sunoco Retail”), a Pennsylvania limited liability company, owns and operates retail stores that sell motor fuel and merchandise
primarily in New Jersey. Sunoco Retail also leases owned sites to commission agents who sell motor fuels to the motoring public on Sunoco Retail's
behalf for a commission.
• Aloha Petroleum LLC, a Delaware limited liability company, distributes motor fuel and operates terminal facilities on the Hawaiian Islands.
• Aloha Petroleum, Ltd. (“Aloha”), a Hawaii corporation, owns and operates retail stores on the Hawaiian Islands and leases owned sites to commission
agents who sell motor fuels to the motoring public on Aloha's behalf for a commission.
•
Peerless Oil & Chemicals, Inc. (“Peerless”), a Delaware corporation, is a terminal operator that distributes fuel products to over 100 locations primarily
within Puerto Rico.
Sunoco LP purchases motor fuel primarily from independent refiners and major oil companies and distributes it throughout the United States, including
Hawaii and Puerto Rico, to:
•
•
•
•
75 company-operated retail stores;
476 independently operated commission agent locations where Sunoco LP sells motor fuel to customers under commission agent arrangements with
such operators;
6,828 retail stores operated by independent operators, which are referred to as “dealers” or “distributors,” pursuant to long-term distribution
agreements; and
approximately 1,600 other commercial customers, including unbranded retail stores, other fuel distributors, school districts and municipalities and
other industrial customers.
Sunoco LP’s operations also include retail operations in Hawaii and New Jersey, credit card services and franchise royalties.
Investment in USAC
The following details the assets of USAC:
USAC’s modern, standardized compression unit fleet is powered primarily by the Caterpillar, Inc.’s 3400, 3500 and 3600 engine classes, which range from
401 to 5,000 horsepower per unit. These larger horsepower units, which USAC defines as 400 horsepower per unit or greater, represented 87.0% of its total
fleet horsepower as of December 31, 2023. The remainder of its
28
Table of Contents
Index to Financial Statements
fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.
The following table provides a summary of USAC’s compression units by horsepower as of December 31, 2023:
Unit Horsepower
Small horsepower
<400
Large horsepower
>400 and <1,000
>1,000
Total large
horsepower
Total horsepower
Fleet
Horsepower
Number of
Units
Horsepower on
Order
(1)
Number of
Units on
(1)
Order
Total
Horsepower
Number of
Units
Percent of Fleet
Horsepower
Percent of
Units
499,752
2,946
—
—
499,752
2,946
13.0 %
54.6 %
416,983
2,858,925
3,275,908
3,775,660
715
1,714
2,429
5,375
—
52,500
52,500
52,500
—
21
21
21
416,983
2,911,425
3,328,408
3,828,160
715
1,735
2,450
5,396
10.9 %
76.1 %
87.0 %
100.0 %
13.2 %
32.2 %
45.4 %
100.0 %
(1)
As of December 31, 2023, USAC had 21 large horsepower units, consisting of 52,500 horsepower, on order for expected delivery during 2024.
All Other
The following details the significant assets in the “All Other” segment.
Compression
We own Dual Drive Technologies, Ltd, which provides compression services to customers engaged in the transportation of natural gas, including our other
segments.
Natural Resources Operations
Our Natural Resources operations primarily involve the management and leasing of coal properties and the subsequent collection of royalties. We also earn
revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees
and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage fees. As of December 31, 2023, we owned or
controlled approximately 730 million tons of proven and probable coal reserves in central and northern Appalachia, properties in eastern Kentucky,
southwestern Virginia and southern West Virginia, and in the Illinois Basin, properties in southern Illinois, Indiana, and western Kentucky and as the
operator of end-user coal handling facilities.
Business Strategy
We believe we have engaged, and will continue to engage, in a well-balanced plan for growth through strategic acquisitions, internally generated
expansion, measures aimed at increasing the profitability of our existing assets and executing cost control measures where appropriate to manage our
operations.
We intend to continue to operate as a diversified, growth-oriented limited partnership. We believe that by pursuing independent operating and growth
strategies we will be best positioned to achieve our objectives. We balance our desire for growth with our goal of preserving a strong balance sheet, ample
liquidity and investment grade credit metrics.
Following is a summary of the business strategies of our core businesses:
Growth through acquisitions. We intend to continue to make strategic acquisitions that offer the opportunity for operational efficiencies and the potential
for increased utilization and expansion of our existing assets while supporting our investment grade credit ratings.
Engage in construction and expansion opportunities. We intend to leverage our existing infrastructure and customer relationships by constructing and
expanding systems to meet new or increased demand for midstream and transportation services.
29
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Index to Financial Statements
Increase cash flow from fee-based businesses. We intend to increase the percentage of our business conducted with third parties under fee-based
arrangements in order to provide for stable, consistent cash flows over long contract periods while reducing exposure to changes in commodity prices.
Enhance profitability of existing assets. We intend to increase the profitability of our existing asset base by adding new volumes under long-term producer
commitments, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.
Competition
Natural Gas
The business of providing natural gas gathering, compression, treating, transportation, storage and marketing services is highly competitive. Since pipelines
are generally the only practical mode of transportation for natural gas over land, the most significant competitors of our transportation and storage segment
are other pipelines. Pipelines typically compete with each other based on location, capacity, price and reliability.
We face competition with respect to retaining and obtaining significant natural gas supplies under terms favorable to us for the gathering, treating and
marketing portions of our business. Our competitors include major integrated oil and gas companies, interstate and intrastate pipelines and other companies
that gather, compress, treat, process, transport and market natural gas. Many of our competitors, such as major oil and gas and pipeline companies, have
capital resources and control supplies of natural gas substantially greater than ours.
In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil and gas companies, and
local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience. Local utilities and distributors
of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.
NGL
In markets served by our NGL pipelines, we face competition with other pipeline companies, including those affiliated with major oil, petrochemical and
natural gas companies, and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees,
reliability and quality of customer service. We face competition with other storage facilities based on fees charged and the ability to receive and distribute
the customer’s products. We compete with a number of NGL fractionators in Texas and Louisiana. Competition for such services is primarily based on the
fractionation fee charged.
Crude Oil and Refined Products
In markets served by our crude oil and refined products pipelines, we face competition from other pipelines as well as rail and truck transportation.
Generally, pipelines are the safest, lowest cost method for long-haul, overland movement of products and crude oil. Therefore, the most significant
competitors for large volume shipments in the areas served by our pipelines are other pipelines. In addition, pipeline operations face competition from rail
and trucks that deliver products in a number of areas that our pipeline operations serve. While their costs may not be competitive for longer hauls or large
volume shipments, rail and trucks compete effectively for incremental and marginal volume in many areas served by our pipelines.
With respect to competition from other pipelines, the primary competitive factors consist of transportation charges, access to crude oil supply and market
demand. Competitive factors in crude oil purchasing and marketing include price and contract flexibility, quantity and quality of services, and accessibility
to end markets.
Our refined product terminals compete with other independent terminals with respect to price, versatility and services provided. The competition primarily
comes from integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with
marketing and trading operations.
Wholesale Fuel Distribution and Retail Marketing
In our wholesale fuel distribution business, we compete primarily with other independent motor fuel distributors. The markets for distribution of wholesale
motor fuel and the large and growing convenience store industry are highly competitive and fragmented, which results in narrow margins. We have
numerous competitors, some of which may have significantly greater resources and name recognition than we do. Significant competitive factors include
the availability of major brands, customer service, price, range of services offered and quality of service, among others. We rely on our ability to provide
value-added and reliable service and to control our operating costs in order to maintain our margins and competitive position.
30
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Index to Financial Statements
In our retail business, we face strong competition in the market for the sale of retail gasoline and merchandise. Our competitors include service stations of
large integrated oil companies, independent gasoline service stations, convenience stores, fast food stores, supermarkets, drugstores, dollar stores, club
stores and other similar retail outlets, some of which are well-recognized national or regional retail systems. The number of competitors varies depending
on the geographical area. It also varies with gasoline and convenience store offerings. The principal competitive factors affecting our retail marketing
operations include gasoline and diesel acquisition costs, site location, product price, selection and quality, site appearance and cleanliness, hours of
operation, store safety, customer loyalty and brand recognition. We compete by pricing gasoline competitively, combining our retail gasoline business with
convenience stores that provide a wide variety of products, and using advertising and promotional campaigns.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been
approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish
guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of
existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk
profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary.
The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a
single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a
single counterparty or affiliated group of counterparties.
Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In
addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including
petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power
generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one
extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of
counterparty non-performance.
During the year ended December 31, 2023, none of our customers individually accounted for more than 10% of our consolidated revenues.
Regulation
Regulation of Interstate Natural Gas Pipelines. The FERC has broad regulatory authority over the business and operations of interstate natural gas
pipelines. Under the NGA, the FERC generally regulates the transportation of natural gas in interstate commerce. For FERC regulatory purposes,
“transportation” includes natural gas pipeline transmission (forwardhauls and backhauls), storage and other services. FGT, Transwestern, Panhandle,
Trunkline, Tiger, Fayetteville Express, Rover, Sea Robin, Midcontinent Express, EGT, MRT, SESH, Stingray, Gulf Run and Southwest Gas transport
natural gas in interstate commerce and thus each qualifies as a “natural-gas company” under the NGA subject to the FERC’s regulatory jurisdiction. We
also hold certain natural gas storage facilities that are subject to the FERC’s regulatory oversight under the NGA.
The FERC’s NGA authority includes the power to:
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approve the siting, construction and operation of new facilities;
review and approve transportation rates;
determine the types of services our regulated assets are permitted to perform;
regulate the terms and conditions associated with these services;
permit the extension or abandonment of services and facilities;
require the maintenance of accounts and records; and
authorize the acquisition and disposition of facilities.
Under the NGA, interstate natural gas companies must charge rates that are just and reasonable. In addition, the NGA prohibits natural gas companies from
unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.
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The maximum rates to be charged by NGA-jurisdictional natural gas companies and their terms and conditions for service are required to be on file with
the FERC. Most natural gas companies are authorized to offer discounts from their FERC-approved maximum just and reasonable rates when competition
warrants such discounts. Natural gas companies are also generally permitted to offer negotiated rates different from rates established in their tariff if, among
other requirements, such companies’ tariffs offer a cost-based recourse rate to a prospective shipper as an alternative to the negotiated rate. Natural gas
companies must make offers of rate discounts and negotiated rates on a basis that is not unduly discriminatory. Existing tariff rates may be challenged by
complaint or on the FERC’s own motion, and if found unjust and unreasonable, may be altered on a prospective basis from no earlier than the date of the
complaint or initiation of a proceeding by the FERC. The FERC must also approve all rate changes. We cannot guarantee that the FERC will allow us to
charge rates that fully recover our costs or continue to pursue its approach of pro-competitive policies.
Pursuant to the FERC’s rules promulgated under the Energy Policy Act of 2005 (the “EPAct of 2005”), it is unlawful for any entity, directly or indirectly, in
connection with the purchase or sale of electric energy or natural gas or the purchase or sale of transmission or transportation services subject to FERC
jurisdiction: (i) to defraud using any device, scheme or artifice; (ii) to make any untrue statement of material fact or omit a material fact; or (iii) to engage
in any act, practice or course of business that operates or would operate as a fraud or deceit. The Commodity Futures Trading Commission (“CFTC”) also
holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act (“CEA”). In
addition, the Federal Trade Commission has the authority under the Federal Trade Commission Act of 1914 and the Energy Independence and Security Act
of 2007 to regulate wholesale petroleum markets. With regard to our physical purchases and sales of natural gas, NGLs or other energy commodities; our
transportation of these energy commodities; and any related hedging activities that we undertake, we are required to observe these anti-market
manipulation laws and related regulations enforced by the FERC, the CFTC and/or the Federal Trade Commission. These agencies hold substantial
enforcement authority, including the ability to assess or seek civil penalties of up to approximately $1.5 million per day per violation, to order disgorgement
of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related
third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Failure to comply with the NGA, the EPAct of 2005, the CEA and the other federal laws and regulations governing our operations and business activities
can result in the imposition of administrative, civil and criminal remedies.
Regulation of Intrastate Natural Gas and NGL Pipelines. Intrastate transportation of natural gas and NGLs is largely regulated by the state in which such
transportation takes place. To the extent that our intrastate natural gas transportation systems transport natural gas in interstate commerce, the rates and
terms and conditions of such services are subject to FERC jurisdiction under Section 311 of the NGPA. The NGPA regulates, among other things, the
provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. The
rates and terms and conditions of some transportation and storage services provided on our pipeline systems of Enable Oklahoma Intrastate Transmission,
LLC, Oasis Pipeline, LP, Houston Pipe Line Company LP, ETC Katy Pipeline, LLC, Energy Transfer Fuel, LP, , Lobo Pipeline Company, LLC, Pelico
Pipeline, LLC, Regency Intrastate Gas LP, Red Bluff Express Pipeline, LLC, Trans-Pecos Pipeline, LLC and Comanche Trail Pipeline, LLC are subject to
FERC regulation pursuant to Section 311 of the NGPA. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and
amounts collected in excess of fair and equitable rates are subject to refund with interest. The terms and conditions of service set forth in the intrastate
facility’s statement of operating conditions are also subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or
greater than our currently approved Section 311 rates, our business may be adversely affected. Failure to observe the service limitations applicable to
transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply
with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in an alteration of
jurisdictional status, and/or the imposition of administrative, civil and criminal remedies.
Our intrastate natural gas operations are also subject to regulation by various agencies in Texas, principally the TRRC. Our intrastate pipeline and storage
operations in Texas are also subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that
rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The rates we charge for
transportation services are deemed just and reasonable under Texas law unless challenged in a customer or TRRC complaint. We cannot predict whether
such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can
result in the imposition of administrative, civil and criminal remedies.
Our NGL pipelines and operations are subject to state statutes and regulations which could impose additional environmental, safety and operational
requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL transportation systems. In
some jurisdictions, state public utility commission oversight may include the possibility of fines, penalties and delays in construction related to these
regulations. In addition, the rates, terms and conditions
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of service for shipments of NGLs on our pipelines are subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy
Act of 1992 (the “EPAct of 1992”) if the NGLs are transported in interstate or foreign commerce whether by our pipelines or other means of transportation.
Since we do not control the entire transportation path of all NGLs shipped on our pipelines, FERC regulation could be triggered by our customers’
transportation decisions.
Regulation of Sales of Natural Gas and NGLs. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the
most part, is not subject to state regulation. The price at which we sell NGLs is not subject to federal or state regulation.
To the extent that we enter into transportation contracts with natural gas pipelines that are subject to FERC regulation, we are subject to FERC
requirements related to the use of such capacity. Any failure on our part to comply with the FERC’s regulations and policies, or with an interstate pipeline’s
tariff, could result in the imposition of civil and criminal penalties.
Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline
transportation are subject to extensive federal and state regulation. The FERC frequently proposes and implements new rules and regulations affecting
those segments of the natural gas industry. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The
stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives
generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations,
and we note that some of the FERC’s regulatory changes may adversely affect the availability and reliability of interruptible transportation service on
interstate pipelines. We do not believe that we will be affected by any such FERC action in a manner that is materially different from other natural gas
marketers with whom we compete.
Regulation of Gathering Pipelines. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA.
We own a number of natural gas pipelines in Texas, Louisiana and West Virginia that we believe meet the traditional tests the FERC uses to establish a
pipeline’s status as a gathering pipeline not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and
federally unregulated gathering services has been the subject of substantial litigation and varying interpretations, so the classification and regulation of our
gathering facilities could be subject to change based on future determinations by the FERC, the courts and Congress. State regulation of gathering facilities
generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our
intrastate pipeline facilities. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally
responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation
transactions and the construction, acquisition, abandonment and interconnection of physical facilities.
Historically, apart from pipeline safety, Louisiana has not acted to exercise this jurisdiction respecting gathering facilities. In Louisiana, our Chalkley
System is regulated as an intrastate transporter, and the Louisiana Office of Conservation has determined that our Whiskey Bay System is a gathering
system.
We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require
gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser
statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit
discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of
restricting the right of an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. For example, the TRRC has approved changes to its
regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly
discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural
gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate
discrimination allegations. Our gathering operations could be adversely affected should they be subject in the future to the application of additional or
different state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations
relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation
pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations,
but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
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Regulation of Interstate Crude Oil, NGL and Products Pipelines. Interstate common carrier pipeline operations are subject to rate regulation by the FERC
under the ICA, the EPAct of 1992, and related rules and orders. The ICA requires that tariff rates for petroleum pipelines be “just and reasonable” and not
unduly discriminatory and that such rates and terms and conditions of service be filed with the FERC. This statute also permits interested persons to
challenge proposed new or changed rates. The FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are
typically not suspended for the maximum allowable period. If the FERC finds that the new or changed rate is unlawful, it may require the carrier to pay
refunds for the period that the rate was in effect. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and
may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of
up to two years prior to the filing of a complaint.
The FERC generally has not investigated interstate rates on its own initiative when those rates, like those we charge, have not been the subject of a protest
or a complaint by a shipper. However, the FERC could investigate our rates at the urging of a third party if the third party is either a current shipper or has a
substantial economic interest in the tariff rate level. Although no assurance can be given that the tariff rates charged by us ultimately will be upheld if
challenged, management believes that the tariff rates now in effect for our pipelines are within the maximum rates allowed under current FERC policies
and precedents.
For many locations served by our product and crude pipelines, we are able to establish negotiated rates. Otherwise, we are permitted to charge cost-based
rates, or in many cases, grandfathered rates based on historical charges or settlements with our customers. To the extent we rely on cost-of-service
ratemaking to establish or support our rates, the issue of the proper allowance for federal and state income taxes could arise. In July 2016, the United States
Court of Appeals for the District of Columbia Circuit issued an opinion in United Airlines, Inc., et al. v. FERC, finding that the FERC had failed to
demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax
allowance in the cost of service underlying its rates, in addition to the discounted cash flow return on equity, would not result in the pipeline partnership
owners double recovering their income taxes. The court vacated the FERC’s order and remanded to the FERC to consider mechanisms for demonstrating
that there is no double recovery as a result of the income tax allowance.
In March 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes in which the FERC found that an impermissible double
recovery results from granting an MLP pipeline both an income tax allowance and a return on equity pursuant to the FERC’s discounted cash flow
methodology. The FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost
of service. The FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent
proceedings. In July 2018, the FERC dismissed requests for rehearing and clarification of the March 2018 Revised Policy Statement, but provided further
guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled
to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax
costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s March 2018 Revised
Policy Statement, as clarified and revised on rehearing. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support
of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the
impacts the FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the
FERC regulated transportation services are unknown at this time. Please see “Item 1A. Risk Factors - Regulatory Matters.”
Effective January 2018, the 2017 Tax Cuts and Jobs Act changed several provisions of the federal tax code, including a reduction in the maximum
corporate tax rate. With the lower tax rate, and as discussed immediately above, the maximum tariff rates allowed by the FERC under its rate base
methodology may be impacted by a lower income tax allowance component. Many of our interstate pipelines, such as Tiger, Midcontinent Express and
Fayetteville Express, have negotiated market rates that were agreed to by customers in connection with long-term contracts entered into to support the
construction of the pipelines, and the rate base methodology does not apply directly to these contracts. Other systems, such as FGT, Transwestern and
Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. In addition, several of these pipelines are covered by approved
settlements, pursuant to which rate filings will be made in the future. As such, the timing and impact to these systems of any tax-related policy change is
unknown at this time and varies based on the circumstances of each pipeline.
The EPAct of 1992 required the FERC to establish a simplified and generally applicable methodology to adjust tariff rates for inflation for interstate
petroleum pipelines. As a result, the FERC adopted an indexing rate methodology which, as currently in effect, allows common carriers to change their
rates within prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. The FERC’s indexing
methodology is subject to review every five years.
In December 2020, FERC issued an order setting the indexed rate at PPI-FG plus 0.78% during the five-year period commencing July 1, 2021 and ending
June 30, 2026. The FERC received requests for rehearing of its December 17, 2020 order
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and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and ending June 30,
2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus 0.21%. FERC
directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period July 1, 2022
through June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to reduce
the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20 order
with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain pending at
the D.C. Circuit. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates. A
pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just
and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in
excess of the pipeline’s increase in costs. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their
rates if those rates would otherwise be above the rate ceiling.
In November 2017, the FERC responded to a petition for declaratory order and issued an order that may have significant impacts on the way a marketer of
crude oil or petroleum products that is affiliated with an interstate pipeline can price its services if those services include transportation on an affiliate’s
interstate pipeline. In particular, the FERC’s November 2017 order prohibits buy/sell arrangements by a marketing affiliate if: (i) the transportation
differential applicable to its affiliate’s interstate pipeline transportation service is at a discount to the affiliated pipeline’s filed rate for that service; and (ii)
the pipeline affiliate subsidizes the loss. Several parties have requested that the FERC clarify its November 2017 order or, in the alternative, grant rehearing
of the November 2017 order. On December 15, 2022, the FERC provided further clarification of its November 2017 order but denied requests for
rehearing.
Finally, on December 15, 2022, the FERC issued a Proposed Policy Statement on Oil Pipeline Affiliate Committed Service, which addresses whether a
contract for committed transportation service complies with the Interstate Commerce Act where the only shipper to obtain the committed service is an
affiliate of the regulated entity. If adopted, the proposed policy statement would create a rebuttable presumption that affiliate contracts are unduly
discriminatory and not just and reasonable in certain circumstances and require a pipeline to produce additional evidentiary support for affiliate contracts
rates and terms. This follows a trend of increased scrutiny by FERC on affiliated contracts across all industries regulated by the FERC. Initial comments on
the proposed policy statement were due on February 13, 2023. The FERC has taken no further action on the proposed policy statement since that time.
Regulation of Intrastate Crude Oil, NGL and Products Pipelines. Some of our crude oil, NGL and products pipelines are subject to regulation by the
TRRC, the Pennsylvania Public Utility Commission and the Oklahoma Corporation Commission. The operations of our joint venture interests are also
subject to regulation in the states in which they operate. The applicable state statutes require that pipeline rates be nondiscriminatory and provide no more
than a fair return on the aggregate value of the pipeline property used to render services. State commissions generally have not initiated an investigation of
rates or practices of petroleum pipelines in the absence of shipper complaints. Complaints to state agencies have been infrequent and are usually resolved
informally. Although management cannot be certain that our intrastate rates ultimately would be upheld if challenged, we believe that, given this history,
the tariffs now in effect are not likely to be challenged or, if challenged, are not likely to be ordered to be reduced.
In addition, as noted above, the rates, terms and conditions for shipments of crude oil, NGLs or products on our pipelines could be subject to regulation by
the FERC under the ICA and the EPAct of 1992 if the crude oil, NGLs or products are transported in interstate or foreign commerce whether by our
pipelines or other means of transportation. Since we do not control the entire transportation path of all crude oil, NGLs or products shipped on our
pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
Regulation of LNG Liquefaction Facilities and LNG Exports. The design, construction, operation, maintenance and expansion of our liquefaction
facilities and the import or export of LNG are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. In contrast to
pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates.
In order to site, construct and operate our LNG terminal, we received and are required to maintain authorizations from the FERC under Section 3 of the
NGA as well as other material governmental and regulatory approvals and permits. The EPAct of 2005 amended Section 3 of the NGA to establish or
clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless
specifically provided otherwise in the EPAct of 2005 amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended
to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting
under federal law.
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Several other material governmental and regulatory approvals and permits are required throughout the life of our LNG terminal. Our FERC authorizations
require us to comply with certain ongoing conditions and reporting obligations and to maintain other regulatory agency approvals throughout the life of our
facilities. For example, throughout the life of our LNG terminal, we are subject to regular reporting requirements to the FERC, PHMSA, and applicable
federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required
approvals as needed, and the need for these approvals and reporting obligations have not materially affected our construction or operations.
The export of LNG produced by any liquefaction facility in the United States requires export authorization from the DOE. The NGA requires the DOE to
approve applications for LNG exports unless such approval would be “inconsistent with the public interest.” In March 2013, Lake Charles LNG Export
obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in
natural gas (the “FTA Authorization”). FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile,
Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and
Singapore. In July 2016, Lake Charles LNG Export also obtained a conditional DOE authorization to export LNG to countries that do not have an FTA for
trade in natural gas (the “Non-FTA Authorization”) subject to commencement of exports no later than December 2020. Lake Charles LNG Export applied
for an extension of the deadline to commence exports under the Non-FTA Authorization to December 2025 and the DOE approved such extension request
in October 2020. Lake Charles LNG Export applied for a second extension of the deadline to commence exports and in April 2023 the DOE denied this
request in connection with a new DOE policy related to extension requests. In light of this new policy, in August 2023, Lake Charles LNG Export applied
for a new Non-FTA Authorization which, if approved, would provide for a new deadline to commence exports to Non-FTA countries, which deadline
would be seven years from the date of such approval. In January 2024, the Biden administration announced a moratorium on the approval of LNG export
authorizations by the DOE and instructed the DOE to conduct studies related to the cumulative impact of LNG exports on domestic natural gas prices,
climate change and other matters. The Biden administration stated that these studies were necessary to enable the DOE to make determinations related to
the statutory “public interest” standard. The DOE has stated that these studies will take several months to complete, after which a draft policy statement
will be made available for public comment prior to finalizing the policy statement. This process is not expected to be completed prior to the U.S.
Presidential election in November 2024.
Regulation of Pipeline Safety. Our pipeline operations are subject to regulation by the DOT, through PHMSA, pursuant to the Natural Gas Pipeline Safety
Act of 1968, as amended (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), with
respect to crude oil, NGLs and condensates. The NGPSA and HLPSA, as amended, govern the design, installation, testing, construction, operation,
replacement and management of natural gas as well as crude oil, NGL and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated
regulations governing pipeline wall thickness, design pressures, maximum operating pressures, pipeline patrols and leak surveys, minimum depth
requirements, and emergency procedures, as well as other matters intended to ensure adequate protection for the public and to prevent accidents and
failures. Additionally, PHMSA has established a series of rules requiring pipeline operators to develop and implement integrity management programs for
certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high consequence areas, which are areas where a
release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive
ecological areas. Failure to comply with the pipeline safety laws and regulations may result in the assessment of sanctions, including administrative, civil or
criminal penalties, the imposition of investigatory, remedial or corrective action obligations, the occurrence of delays in permitting or the performance of
projects, or the issuance of injunctions limiting or prohibiting some or all of our operations in the affected area.
The HLPSA and NGPSA have been amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) and
the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016. The 2011 Pipeline Safety Act increased the penalties for safety violations,
established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new
regulatory requirements by PHMSA for existing pipelines. The 2011 Pipeline Safety Act doubled the maximum administrative fines for safety violations
from $0.1 million to $0.2 million for a single violation and from $1 million to $2 million for a related series of violations, but provided that these maximum
penalty caps do not apply to certain civil enforcement actions. In May 2021, PHMSA issued a final rule increasing those maximum civil penalties to
approximately $0.2 million per day, with a maximum of approximately $2 million for a series of violations, to account for inflation. Upon reauthorization
of PHMSA, Congress often directs the agency to complete certain rulemakings. For example, in the Consolidated Appropriations Bill for Fiscal Year 2021,
Congress reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory actions, including the “Pipeline
Safety: Class Location Change Requirements” and the “Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking. To
that end, in November 2021, PHMSA issued a final rule significantly expanding reporting and safety requirements of operators of gas gathering pipelines.
The rule imposes safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will
impose criteria for
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inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to
certain gas gathering pipelines with large diameters and high operating pressures. Additionally, in June 2021, PHMSA issued an Advisory Bulletin advising
pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks
and minimization of natural gas from related pipeline facilities. PHMSA, together with state regulators, are expected to commence and complete inspection
of these plans in 2022.
In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which we
conduct operations typically have developed regulatory programs that parallel the federal regulatory scheme and are applicable to intrastate pipelines.
Under such state regulatory programs, states have the authority to conduct pipeline inspections, to investigate accidents and to oversee compliance and
enforcement, safety programs and record maintenance and reporting. Congress, PHMSA and individual states may pass or implement additional safety
requirements that could result in increased compliance costs for us and other companies in our industry. For example, federal construction, maintenance
and inspection standards under the NGPSA that apply to pipelines in relatively populated areas may not apply to gathering lines running through rural
regions. However, in October 2019, PHMSA published two further final rules, in addition to the November 2021 rule discussed above, that create or
expand reporting, inspection, maintenance, and other pipeline safety obligations, including, among other things, extending pipeline integrity assessments to
pipelines in certain locations, including newly-defined “Moderate Consequence Areas” (“MCAs”). Specifically, PHMSA issued a final rule imposing
numerous requirements on onshore gas transmission pipelines relating to maximum allowable operating pressure (“MAOP”), reconfirmation and
exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs, non-High Consequence Area (“HCAs”), and Class 3 and
Class 4 areas by 2023, and the consideration of seismicity as a risk factor in integrity management. Establishing MAOP through reliance on historical
pipeline design, construction, inspection, testing, and other records requires that such records be traceable, verifiable, and complete. Locating such records
and, in the absence of any such records, verifying maximum pressures through physical testing (including hydrotesting) or modifying or replacing facilities
to meet the demands of such pressures, could significantly increase our costs. Failure to locate such records or verify maximum pressures could result in
reductions of allowable operating pressures, which would reduce available capacity on our pipelines. PHMSA’s second final rule, published in October
2019, applicable to hazardous liquid transmission and gathering pipelines, significantly extended and expanded the reach of certain integrity management
requirements, use of in-line inspection tools by 2039 (unless the pipeline cannot be modified to permit such use), increased annual, accident, and safety-
related conditional reporting requirements, and expanded use of leak detection systems beyond HCAs. The integrity-related requirements and other
provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and the PIPES Act of 2020, as well as any implementation of PHMSA rules
thereunder, could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis and incur increased
operating costs that could have a material adverse effect on our results of operations and financial condition.
In another example of how future legal requirements could result in increased compliance costs, notwithstanding the applicability of the federal OSHA’s
Process Safety Management (“PSM”) regulations and the EPA’s Risk Management Planning (“RMP”) requirements at regulated facilities, PHMSA and one
or more state regulators, including the TRRC, have in recent years, expanded the scope of their regulatory inspections to include certain in-plant equipment
and pipelines found within NGL fractionation facilities and associated storage facilities, in order to assess compliance of such equipment and pipelines with
hazardous liquid pipeline safety requirements. To the extent that these actions are pursued by PHMSA, midstream operators of NGL fractionation facilities
and associated storage facilities subject to such inspection may be required to make operational changes or modifications at their facilities to meet standards
beyond current PSM and RMP requirements, which changes or modifications may result in additional capital costs, possible operational delays and
increased costs of operation that, in some instances, may be significant.
Environmental Matters
General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering, processing,
storage and transmission of natural gas and the storage and transportation of NGLs, crude oil and refined products is subject to stringent U.S. federal, tribal,
state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and
disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Similar or more stringent laws also exist in Canada.
Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines
and criminal sanctions, third-party claims for personal injury or property damage, capital expenditures to retrofit or upgrade our facilities and programs, or
curtailment or cancellation of permits on operations. As with the industry generally, compliance with existing and anticipated environmental laws and
regulations increases our overall cost of doing business, including our cost of planning, permitting, constructing and operating our plants, pipelines and
other facilities. As a result of these laws and regulations, our construction and operation costs include capital, operating and maintenance cost items
necessary to maintain or upgrade our equipment and facilities.
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We have implemented procedures designed to ensure that governmental environmental approvals for both existing operations and those under construction
are updated as circumstances require. Historically, our environmental compliance costs have not had a material adverse effect on our business, results of
operations or financial condition; however, there can be no assurance that such costs will not be material in the future. For example, we cannot be certain
that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent environmental laws
and regulations or unanticipated events will not arise in the future and give rise to environmental liabilities that could have a material adverse effect on our
business, financial condition or results of operations.
Uncertainty about the future course of regulation continues to exist following the change in U.S. presidential administrations in January 2021. Upon taking
office, the Biden Administration issued an executive order directing all federal agencies to review and take action to address any federal regulations
promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, several regulatory
developments have occurred, but it remains unclear the degree to which this will continue. The executive order also established an Interagency Working
Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the
“social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the
social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group has not yet published its final
recommendations. Further regulation of air emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand
for oil and natural gas and, in turn, have a material adverse effect on our business, financial condition or results of operations.
Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of
hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination
of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances
and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, the
Comprehensive Environmental Response, Compensation and Liability Act, as amended, (“CERCLA”), also known as the “Superfund” law, and
comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a
release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies
that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be
subject to strict, joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous
substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and
comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, third parties to take actions in response to threats to the
public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants
released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,”
in the course of our ordinary operations we generate wastes that may fall within that definition or that may be subject to other waste disposal laws and
regulations. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes
have been disposed.
We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal Resource Conservation and Recovery Act, as
amended, (“RCRA”) and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA hazardous waste
requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent non-hazardous
management standards. From time to time, the EPA has considered or third parties have petitioned the agency on the adoption of stricter handling, storage
and disposal standards for nonhazardous wastes, including certain wastes associated with the exploration, development and production of crude oil and
natural gas. For example, in 2016, the EPA entered into an agreement with several environmental groups to analyze certain Subtitle D criteria regulations
pertaining to oil and gas wastes and, if necessary, revise them. In response to the decree, in April 2019, the EPA signed a determination that revision of the
regulations is not necessary at this time. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be
designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of
RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes such as these examples in applicable regulations
may result in a material increase in our capital expenditures or plant operating and maintenance expense and, in the case of our oil and natural gas
exploration and production customers, could result in increased operating costs for those customers and a corresponding decrease in demand for our
processing, transportation and storage services.
We currently own or lease sites that have been used over the years by prior owners and lessees and by us for various activities related to gathering,
processing, storage and transmission of natural gas, NGLs, crude oil and refined products. Waste disposal practices within the oil and gas industry have
improved over the years with the passage and implementation of various
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environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or otherwise released on or under various sites
during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these releases may have occurred
during the ownership or operation of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws,
we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or
contamination (including soil and groundwater contamination) or to prevent the migration of contamination.
As of December 31, 2023 and 2022, accruals of $277 million and $282 million, respectively, were recorded in our consolidated balance sheets as accrued
and other current liabilities and other non-current liabilities for estimated environmental liabilities.
The Partnership is subject to extensive and frequently changing federal, tribal, state and local laws and regulations, including those relating to the discharge
of materials into the environment or that otherwise relate to the protection of the environment, waste management and the characteristics and composition
of fuels. These laws and regulations require environmental assessment and remediation efforts at many of ETC Sunoco’s facilities and at formerly owned
or third-party sites. Accruals for these environmental remediation activities amounted to $213 million and $219 million at December 31, 2023 and 2022,
respectively, which is included in the total accruals above. These legacy sites that are subject to environmental assessments include formerly owned
terminals and other logistics assets, retail sites that are no longer operated by ETC Sunoco, closed and/or sold refineries and other formerly owned sites. We
have established a wholly owned captive insurance company for these legacy sites that are no longer operating. The premiums paid to the captive insurance
company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims
expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums
paid to the captive insurance company. As of December 31, 2023, the captive insurance company held $140 million of cash and investments.
The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites where an assessment has indicated that
cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on currently available information,
estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. It is often
extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing technologies and their associated
costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to identify and evaluate remediation
alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Under various environmental laws, including the RCRA, the Partnership has initiated corrective remedial action at certain of its facilities, formerly owned
facilities and at certain third-party sites. At the Partnership’s major manufacturing facilities, we have typically assumed continued industrial use and a
containment/remediation strategy focused on eliminating unacceptable risks to human health or the environment. The remediation accruals for these sites
reflect that strategy. Accruals include amounts designed to prevent or mitigate off-site migration and to contain the impact on the facility property, as well
as to address known, discrete areas requiring remediation within the plants. Remedial activities include, for example, closure of RCRA waste management
units, recovery of hydrocarbons, handling of impacted soil, mitigation of surface water impacts and prevention or mitigation of off-site migration. A change
in this approach as a result of changing the intended use of a property or a sale to a third party could result in a comparatively higher cost remediation
strategy in the future.
In general, a remediation site or issue is typically evaluated on an individual basis based upon information available for the site or issue and no pooling or
statistical analysis is used to evaluate an aggregate risk for a group of similar items (for example, service station sites) in determining the amount of
probable loss accrual to be recorded. The estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many
cases, it is difficult to determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance
allows us the minimum amount of the range to accrue. Accordingly, the low end of the range often represents the amount of loss which has been recorded.
The Partnership’s consolidated balance sheet reflected $277 million in environmental accruals as of December 31, 2023.
In summary, total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the
determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the
technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially
responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of
consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the
number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely
extend over many years, but management can provide no assurance that it would be
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over many years. If changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted, such
changes could materially and adversely impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to
time, significant charges against income for environmental remediation may occur. And while management does not believe that any such charges would
have a material adverse impact on the Partnership’s consolidated financial position, it can provide no assurance.
Transwestern conducts soil and groundwater remediation at a number of its facilities. Some of the cleanup activities include remediation of several
compressor sites on the Transwestern system for contamination by PCBs, and the costs of this work are not eligible for recovery in rates. The total accrued
future estimated cost of remediation activities expected to continue through 2025 is $3 million, which is included in the total environmental accruals
mentioned above. Transwestern received FERC approval for rate recovery of projected soil and groundwater remediation costs not related to PCBs
effective April 1, 2007. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing
potential PCB contamination. Future costs cannot be reasonably estimated because remediation activities are undertaken as potential claims are made by
customers and former customers. Such future costs are not expected to have a material impact on our financial position, results of operations or cash flows,
but management can provide no assurance.
Air Emissions. Our operations are subject to the federal Clean Air Act, as amended, and comparable state laws and regulations. These laws and regulations
regulate emissions of air pollutants from various industrial sources, including our processing plants, and also impose various monitoring and reporting
requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, such
as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain
and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to
limit emissions. We will incur capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating
permits and approvals for air emissions. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent
regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air
pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities.
Historically, our costs for compliance with existing Clean Air Act and comparable state law requirements have not had a material adverse effect on our
results of operations; however, there can be no assurance that such costs will not be material in the future. The EPA and state agencies are often
considering, proposing or finalizing new regulations that could impact our existing operations and the costs and timing of new infrastructure development.
For example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”)
for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA completed attainment/non-attainment
designations in 2018, and states with moderate or high non-attainment areas must submit state implementation plans to the EPA by October 2021. By law,
the EPA must review each NAAQS every five years. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS for
ozone. However, the Biden Administration has announced plans to formally review this decision and consider instituting a more stringent standard.
Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in
newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could
apply to our customers’ operations. Compliance with this or other new regulations could, among other things, require installation of new emission controls
on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could
adversely impact our business.
Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended, (“Clean Water Act”) and comparable state laws impose restrictions and
strict controls regarding the discharge of pollutants, including hydrocarbon-bearing wastes, into state waters and waters of the United States. Pursuant to the
Clean Water Act and similar state laws, a National Pollutant Discharge Elimination System, or state permit, or both, must be obtained to discharge
pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under
general permits be obtained by subject facilities for discharges of storm water runoff. The Clean Water Act also prohibits the discharge of dredge and fill
material in regulated waters, including wetlands, unless authorized by permit. In June 2015, the EPA and the United States Corps of Engineers (“USACE”)
published a final rule attempting to clarify the federal jurisdictional reach over “waters of the United States” (“WOTUS”), but legal challenges to this rule
followed. In January 2023,
the EPA and the USACE published a final rule that would restore water protections that were in place prior to 2015. However, the January 2023 rule was
challenged and is currently enjoined in 27 states. Separately, in May 2023, the U.S. Supreme Court released its opinion in Sackett v. EPA, which used the
“continuous surface connection” test to determine whether wetlands qualify as WOTUS. The Sackett decision invalidated certain parts of the January 2023
rule and significantly narrowed its scope, resulting in a revised rule being issued in September 2023; however, the September 2023 rule did not define the
term “continuous surface connection.” Due to the injunction, implementation of the rule currently varies by state, and it remains unclear how broadly the
agencies will interpret the term “continuous surface connection.” As a result of these developments,
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the scope of jurisdiction under the Clean Water Act is uncertain at this time, but to the extent any rule expands the scope of the Clean Water Act’s
jurisdiction, our operations as well as our exploration and production customers’ drilling programs could incur increased costs and delays with respect to
obtaining permits for dredge and fill activities in wetland areas.
Additionally, for over 35 years, the USACE has authorized construction, maintenance, and repair of pipelines under a streamlined Nationwide Permit
(“NWP”) program. From time to time, environmental groups have challenged the NWP program, and, in April 2020, the U.S. District Court for the District
of Montana determined that NWP 12 failed to comply with consultation requirements under the federal Endangered Species Act. The district court vacated
NWP 12 and enjoined the issuance of new authorizations for oil and gas pipeline projects under the permit. In January 2021, the EPA and USACE issued a
final rule reissuing and restricting NWP 12 to oil and gas pipelines and creating a new nationwide permit to authorize certain dredge and fill activities
associated with utility lines conveying other substances such as brine, potable water, wastewater, and other substances excluding oil, natural gas, products
derived from oil or natural gas, and electricity. The Biden Administration was asked to examine the final rule. Additionally, an October 2021 decision by
the District Court for the Northern District of California resulted in the vacatur of a 2020 rule revising the Clean Water Act Section 401 certification
process, following which, in November 2021, USACE announced that it has temporarily suspended finalization of certain permitting decisions, including
under NWP 12, that rely on a Section 401 certification or waiver under the 2020 rule. This vacatur was subsequently stayed by the U.S. Supreme Court in
April 2022, and the EPA published a final rule to update and replace the relevant regulations in September 2023. We could face significant delays and
financial costs if we must obtain individual permit coverage from USACE for our projects as a result of any future actions.
Spills. Our operations can result in the discharge of regulated substances, including NGLs, crude oil or other products. The Clean Water Act, as amended by
the federal Oil Pollution Act of 1990, as amended, (“OPA”), and comparable state laws impose restrictions and strict controls regarding the discharge of
regulated substances into state waters or waters of the United States. The Clean Water Act and comparable state laws can impose substantial administrative,
civil and criminal penalties for non-compliance including spills and other non-authorized discharges. The OPA subjects owners of covered facilities to strict
joint and potentially unlimited liability for removal costs and other consequences of a release of oil, where the release is into navigable waters, along
shorelines or in the exclusive economic zone of the United States. Spill prevention control and countermeasure requirements of the Clean Water Act and
some state laws require that containment dikes and similar structures be installed to help prevent the impact on navigable waters in the event of a release of
oil. PHMSA, the EPA, or various state regulatory agencies, has approved our oil spill emergency response plans that are to be used in the event of a spill
incident.
In addition, some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater
conditions. Our management believes that compliance with existing permits and compliance with foreseeable new permit requirements will not have a
material adverse effect on our results of operations, financial position or expected cash flows.
Endangered Species. The Endangered Species Act, as amended, restricts activities that may affect endangered or threatened species or their habitat. Similar
protections are offered to migratory birds under the Migratory Bird Treaty Act. We may operate in areas that are currently designated as a habitat for
endangered or threatened species or where the discovery of previously unidentified endangered species, or the designation of additional species as
endangered or threatened may occur in which event such one or more developments could cause us to incur additional costs, to develop habitat
conservation plans, to become subject to expansion or operating restrictions, or bans in the affected areas. Moreover, such designation of previously
unprotected species as threatened or endangered in areas where our oil and natural gas exploration and production customers operate could cause our
customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of
operations, which could reduce demand for our services.
Climate Change. Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been
made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of
greenhouse gases (“GHGs”). These efforts have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking
programs, and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has
been implemented at the federal level to date. However, Canada has implemented a federal carbon pricing regime, and, in the United States, President
Biden has announced that he intends to pursue substantial reductions in GHG emissions, particularly from the oil and gas sector. For example, on January
27, 2021, President Biden signed an executive order that commits to substantial action on climate change, calling for, among other things, the increased use
of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of
offshore wind energy, and an increased emphasis on climate-related risks across government agencies and economic sectors. On January 26, 2024,
President Biden announced a temporary pause on pending decisions on new exports of LNG to countries that the United States does not have free trade
agreements with, pending DOE review of the underlying analyses for authorizations. Additionally, the EPA has adopted rules under authority of the Clean
Air Act that, among other things, establish Potential for Significant Deterioration
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(“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are also potential major sources of
certain principal, or criteria, pollutant emissions, which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best
available control technology” standards for those GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of
GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore processing, transmission,
storage and distribution facilities. In October 2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural
gas industry, including gathering and boosting facilities and blowdowns of natural gas transmission pipelines.
Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. In June 2016, the EPA
published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil
and natural gas sector to reduce these methane gas and volatile organic compound (“VOC”) emissions. These Subpart OOOOa standards expand previously
issued NSPS published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring
additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas
compressor and booster stations. In September 2020, the EPA removed natural gas transmission and storage operations from this sector and rescinded the
methane-specific requirements of the rule for production and processing facilities. However, Congress passed, and President Biden signed into law, a
revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. Additionally, in December 2023, the EPA issued a final rule that established
OOOOb new source and OOOOc first-time existing source standards of performance for GHG and VOC emissions for the crude oil and natural gas well
sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of
affected emission units or processes will have to comply with specific standards of performance that include leak detection using optical gas imaging and
subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and
maintenance requirements, and so-called “green well” completion requirements. The December 2023 rule also establishes a “super-emitter” response
program that would allow third parties to make reports to the EPA of large methane emission events, triggering certain investigation and repair
requirements. Fines and penalties for violations of these rules could be substantial. GHG emission standards, including methane emissions imposed on the
oil and gas sector, could result in increased costs to our operations as well as result in delays or curtailment in such operations, which costs, delays or
curtailment could adversely affect our business. Several states have also adopted, or are considering adopting, regulations related to GHG emissions, some
of which are more stringent than those implemented by the federal government.
At the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United
Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit
individually-determined, non-binding emission reduction goals every five years beginning in 2020. Although the United States withdrew from the Paris
Agreement under the Trump administration, President Biden recommitted the United States in February 2021, and, in April 2021, announced a new, more
rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The
international community gathered again in Glasgow in November 2021 at the 26th Conference of the Parties (“COP26”) during which multiple
announcements were made, including a call for parties to eliminate fossil fuel subsidies, amongst other measures. Relatedly, the United States and
European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global
methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. In December 2023, at the 28th
Conference of the Parties (“COP28”), the parties signed onto an agreement to transition away from fossil fuels in energy systems and increase renewable
energy capacity, although no timeline for doing so was set.
President Biden’s January 2021 climate change executive order directed the Secretary of the Interior to pause new oil and natural gas leasing on public
lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust
royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for
corresponding climate costs. The executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the
extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. As noted above, a separate executive order issued in January
2021 established a Working Group that is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost
of nitrous oxide” and “social cost of methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and
nitrous oxide and sought public comment on these estimates. The Working Group has not yet published its final recommendations. However, in September
2023, President Biden issued an executive order directing agencies to consider the Working Group’s social cost of a project’s greenhouse gases when
conducting environmental reviews of major federal actions.
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The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict
emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business,
financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas companies
have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being aware of the
impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers. Various investors are becoming
increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into other sectors.
Institutional lenders who provide financing for fossil fuel energy companies also have become more attentive to sustainable lending practices that favor
“clean” power sources such as wind and solar photovoltaic, making those sources more attractive for investment, and some of them may elect not to
provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that
commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of
GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net
zero by 2050. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy
companies. In late 2020, the Federal Reserve joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators
focused on addressing climate-related risks in the financial sector. More recently, in November 2021, the Federal Reserve issued a statement in support of
the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory
authorities. Such efforts could make it more difficult to secure funding for exploration and production or midstream activities and could also increase the
cost of obtaining financings and/or negatively affect terms of financings.
Finally, climatic events in the areas in which we operate, whether from climate change or otherwise, can cause disruptions and, in some cases, delays in, or
suspension of, our services. These events, including but not limited to drought, winter storms, wildfire, extreme temperatures or flooding, may become
more intense or more frequent as a result of climate change and could have an adverse effect on our continued operations. If such effects were to occur, our
operations could be adversely affected in various ways, including damages to our facilities or our customers’ facilities from powerful winds or rising
waters, or increased costs for, or difficulty obtaining, insurance. Another possible consequence of climate change is increased volatility in seasonal
temperatures. The market for our NGLs and natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so
any changes in climate could affect the market for the fuels that we transport, and thus demand for our services. Despite the use of the term “global
warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially
colder than their historical averages. As a result, it is difficult to predict how the market for our products could be affected by increased temperature
volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.
We recognize the need to decrease emissions and integrate alternative energy sources into our operations, and we actively pursue economically beneficial
opportunities to reduce our environmental footprint throughout our operations. Protecting public health and the environment is the primary initiative of our
environmental management teams, both in the construction and operation of our assets. These teams have worked to reduce our emissions and minimize
our environmental impact. Some examples of our teams’ efforts include:
•
•
•
•
•
•
in our natural gas compression business, the use of our proprietary dual-drive technology, which offers the ability to switch compression drivers
between an electric motor and a natural gas engine, allowed us to reduce our emissions of nitrogen oxide, carbon monoxide, CO2 and VOCs;
the installation of approximately 12,000 low-emission pneumatic devices throughout our pipeline systems has allowed us to safely and efficiently
adjust and control our operations and reduce methane emissions;
the voluntary installation of thermal oxidizers, which destroy VOCs and convert methane to CO2 (a less carbon-intense GHG), thereby reducing VOC
and methane emissions by 98% or more at many of our more than 50 natural gas processing and sweetening plants;
the implementation of an innovative liquids management process throughout much of our natural gas gathering pipeline system has allowed us to
minimize flash emissions and methane emissions;
the use of optical gas imaging cameras at our more than 2,200 gas gathering and processing facilities as part of our leak detection and repair program
allow us to reduce emissions, improve safety, reduce costs, prevent product loss, and maintain equipment integrity;
the use of in-line inspection tools, or smart pigs, allow us to detect corrosion, cracks or other defects along our pipeline systems thereby protecting the
environment and the safety of our communities, employees and landowners; and
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•
the use of other methods, including pipeline blowdown direct injection, liquids pipeline system optimization, crude oil truck unloading and direct
injection, all of which help to reduce emissions and the release of methane into the atmosphere across our operations.
Powering our assets through renewable energy sources is an established part of our operations where it is economically viable to do so. We have reduced
our carbon footprint by using a diversified mix of energy sources, including solar and wind power to generate electrical power. The percentage of electrical
energy we purchase on a given day originating from solar and wind sources is approaching 20%. Since 2019, we have entered into dedicated solar contracts
to purchase 148 megawatts of solar power to support the operations of our assets. We also operate approximately 18,000 solar panel-powered metering
stations across the United States.
In February 2021, we announced the formation of our alternative energy group. This group is tasked with increasing our efforts to support renewable
energy projects such as solar and/or wind farms, either as a power purchaser, or in a partnership with third party developers, when they make economic
sense. This group is also focused on developing alternative energy projects aimed at reducing the environmental footprint throughout our operations,
including a variety of projects related to carbon capture, utilization and sequestration of CO2.
While our environmental management initiatives have not materially impacted our capital expenditures or results of operations, we recognize that the non-
financial impacts of these initiatives are of interest to our investors and other stakeholders. We voluntarily publish additional information on those
initiatives; however, much of that separately published information is excluded from this annual report on Form 10-K if it is not material in the context of
the consolidated Partnership and/or if it is not required by the instructions to Form 10-K. For additional information on our environmental management
initiatives, including our efforts to curb GHG emissions and to integrate alternative energy sources, please see our Corporate Responsibility Report
available on our website at http://www.energytransfer.com/corporate-responsibility. Information contained on our website is not part of this report.
Employee Health and Safety. We are subject to the requirements of the federal OSHA and comparable state laws that regulate the protection of the health
and safety of workers. In addition, the Occupational Safety and Health Administration’s hazard communication standard requires that information be
maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government
authorities and citizens. Historically, our costs for OSHA required activities, including general industry standards, recordkeeping requirements, and
monitoring of occupational exposure to regulated substances, have not had a material adverse effect on our results of operations but there is no assurance
that such costs will not be material in the future.
Natural Resource Reviews. The National Environmental Policy Act (“NEPA”) provides for an environmental impact assessment process in connection with
certain projects that involve federal lands or require approvals by federal agencies. The NEPA process implicates a number of other environmental laws and
regulations, including the Endangered Species Act, Migratory Bird Treaty Act, Rivers and Harbors Act, Clean Water Act, Bald and Golden Eagle
Protection Act, Fish and Wildlife Coordination Act, Marine Mammal Protection Act and National Historic Preservation Act, often requiring coordination
with numerous governmental authorities. The NEPA review process can be lengthy and subjective, resulting in delays in obtaining federal approvals for
projects. Our projects that are subject to the NEPA can include pipeline construction and pipeline integrity projects that involve federal lands or require
approvals by federal agencies. In July 2020, the Council on Environmental Quality (“CEQ”) issued final revisions to NEPA regulations that seek to
conform the scope of direct, indirect, and cumulative impact analyses for proposed projects subject to NEPA with existing case law. However, in October
2021, the CEQ published a proposed rule to restore, in general, NEPA regulations that were in effect before being modified by the 2020 revisions. This rule
was finalized in April 2022, and CEQ issued additional proposed revisions to NEPA regulations in July 2023. More stringent environmental impact
analyses under or third-party challenges with respect to the sufficiency of any environmental impact statement or assessment prepared pursuant to NEPA
could adversely impact such projects in the form of delays or increased compliance and mitigations costs.
Indigenous Protections. Part of our operations cross land that has historically been apportioned to various Native American/First Nations tribes
(“Indigenous Peoples”), who may exercise significant jurisdiction and sovereignty over their lands. Indigenous Peoples may also have certain treaty rights
and rights to consultation on projects that may affect such lands. Our operations may be impacted to the extent these tribal governments are found to have
and choose to act upon such jurisdiction over lands where we operate. For example, in 2020, the Supreme Court ruled in McGirt v. Oklahoma that the
Muscogee (Creek) Nation reservation in Eastern Oklahoma has not been disestablished. Although the court’s ruling indicates that it is limited to criminal
law, as applied within the Muscogee (Creek) Nation reservation, the ruling may have significant potential implications for civil law, both in the Muscogee
(Creek) Nation reservation and other reservations that may similarly be found to not have been disestablished. State courts in Oklahoma have applied the
analysis in McGirt in ruling that the Cherokee, Chickasaw, Seminole, and Choctaw reservations likewise had not been disestablished.
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On October 1, 2020, the EPA granted approval to the State of Oklahoma under Section 10211(a) of the Safe, Accountable, Flexible, Efficient
Transportation Equity Act of 2005 (the “SAFETE Act”) to administer all of the State’s existing EPA-approved regulatory programs to Indian Country
within the state except: Indian allotments to which Indians titles have not been extinguished; lands that are held in trust by the United States on behalf of
any Indian or Tribe; lands that are owned in fee by any Tribe where title was acquired through a treaty with the United States to which such tribe is a party
and that have never been allotted to any citizen or member of such Tribe. The approval extends the State’s authority for existing EPA-approved regulatory
programs to all lands within the State to which the State applied such programs prior to the U.S. Supreme Court’s ruling in McGirt. However, several
Tribes expressed dissatisfaction with the consultation process performed in relation to this approval, and, in December 2021, the EPA proposed to withdraw
and reconsider the October 2020 decision. Additionally, the SAFETE Act provides that any Tribe in Oklahoma may seek “Treatment as a State” by the
EPA, and it is possible that one or more of the Tribes in Oklahoma may seek such an approval from the EPA. At this time, we cannot predict how these
jurisdictional issues may ultimately be resolved.
Human Capital Management
As of December 31, 2023, Energy Transfer and its consolidated subsidiaries employed an aggregate of 13,786 employees, 1,422 of which are represented
by labor unions. We believe that our relations with our employees are good.
Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our core values and that respects all
people and cultures, promotes safety, and focuses on the protection of public health and being a good steward of the environment.
Ethics and Values. We are committed to operating our business in a manner that honors and respects all people and the communities in which we do
business. We recognize that people are our most valued resource, and we are committed to hiring and investing in employees who strive for excellence and
live by our core values: working safely, corporate stewardship, ethics and integrity, entrepreneurial mindset, our people, excellence and results, and social
responsibility. We value our employees for what they bring to our organization by embracing those from all backgrounds, cultures, and experiences. We
also believe that the keys to our successes have been the cultivation of an atmosphere of inclusion and respect within our family of partnerships and
sustaining organizations that promote diversity and provide support across all communities in which we do business. These are the principles upon which
we build and strengthen relationships among our people, our stakeholders, and those within the communities in which we do business.
Respecting All People and All Cultures. We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in the best interest
of the Partnership, its Unitholders, its customers, and the industry in general. In all applicable instances, the policies of the Partnership require that the
business of the Partnership be conducted in a lawful and ethical manner. Every employee acting on behalf of the Partnership must adhere to these policies.
Please refer to “Item 10. Directors, Executive Officers and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.
Commitment to Public Health, Safety and the Environment. Protecting public health and being a good steward of the environment is an important initiative
for our environmental management teams, both in the construction and operation of our assets. These teams consist of environmental engineers, scientists
and geologists who seek to responsibly and efficiently reduce emissions associated with our operations, be a good steward of the land, water and air in the
areas where we operate, and remain in compliance with all applicable regulations. Our environmental, health and safety department’s more than 200
environmental and safety professionals provide environmental and safety training to our field representatives. This group also assists others throughout the
organization by identifying continuous training for personnel, including training that is required by applicable laws, regulations, standards, and permit
conditions. It is our policy to communicate our safety standards and expectations to all employees and contractors with the expectation that each individual
has the obligation to make safety the highest priority. Our safety culture aims to promote an open environment for discovering, resolving, and sharing
safety challenges. We strive to eliminate unwanted safety events through a comprehensive process that promotes leadership, employee involvement,
communication, personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes,
maintaining clean facilities, contractor safety, and personal wellness. Energy Transfer’s goal is operational excellence, which means an injury- and incident-
free workplace. To achieve this, we strive to hire and maintain the most qualified and dedicated workforce in the industry and make safety and safety
accountability part of our daily operations. We believe that the OSHA Total Reportable Incident Rate (“TRIR”) is a key performance indicator that we use
to evaluate our safety programs. TRIR can provide companies with a look at their safety record performance for the year by calculating the number of
recordable injury and illness incidents per 200,000 hours worked. Our TRIR was 0.77 for 2023, out of approximately 18.9 million hours worked during the
year, compared to a TRIR of 1.01 for 2022. We believe the Partnership’s low TRIR speaks to the Partnership’s investment in and focus on safety and
environmental compliance as well as the reliability of our assets.
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For additional information on our Human Capital Management initiatives, please see our Corporate Responsibility Report available on our website at
http://www.energytransfer.com/corporate-responsibility. Please note that the preceding internet address is for information purposes only and is not intended
to be a hyperlink. Accordingly, no information found and/or provided at such internet address or contained on our website in general is intended or deemed
to be incorporated by reference in this report.
SEC Reporting
We file or furnish annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any related amendments and
supplements thereto with the SEC. From time to time, we may also file registration statements and related documents pertaining to equity or debt offerings.
The SEC maintains an internet website at http://www.sec.gov that contains reports, proxy and information statements and other information regarding
issuers that file electronically with the SEC.
We provide electronic access, free of charge, to our periodic and current reports, and amendments to these reports, on our internet website located at
http://www.energytransfer.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with
the SEC. Information contained on our website is not part of this report.
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The following is a summary of important risk factors that are specific to our business, industry and partnership structure that could materially impact our
future performance and results of operations. These risk factors should be reviewed when considering an investment in our securities. These are not all the
risks we face. Other factors that we face in the ordinary course of business that are currently considered immaterial or that are currently unknown to us may
impact our future operations.
ITEM 1A. RISK FACTORS
Risk Factor Summary
Risks Related to the Partnership’s Business
Results of Operations and Financial Condition. Our results of operations and financial condition could be impacted by many risks that are beyond our
control, including the following:
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fluctuations in the demand for and price of natural gas, NGLs, crude oil and refined products;
an impairment of goodwill and intangible assets;
an interruption of supply of crude oil to our facilities;
the loss of any key producers or customers;
failure to retain or replace existing customers or volumes due to declining demand or increased competition;
unfavorable changes in natural gas price spreads between two or more physical locations;
production declines over time, which we may not be able to replace with production from newly drilled wells;
competition for water resources or limitations on water usage for hydraulic fracturing;
our customers’ ability to use our pipelines and third-party pipelines over which we have no control;
the inability to access or continue to access lands owned by third parties;
the overall forward market for crude oil and other products we store;
a natural disaster, catastrophe, terrorist attack or other similar event;
extreme weather events that may be more severe or frequent than historically experienced and that may be attributable to changes in climate due to the
adverse effects of an industrialized economy;
union disputes and strikes or work stoppages by unionized employees;
cybersecurity breaches and other disruptions or failures of our information systems;
failure to establish or maintain adequate corporate governance;
product liability claims and litigation, or increased insurance costs including as a result of increased risks due to the potential adverse effects of
changes in climate;
actions taken by certain of our joint ventures that we do not control;
increasing levels of congestion in the Houston Ship Channel;
the costs of providing pension and other postretirement health care benefits and related funding requirements;
•
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• mergers among customers and competitors;
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fraudulent activity or misuse of proprietary data involving our outsourcing partners; and
losses resulting from the use of derivative financial instruments.
Indebtedness. Our business, results of operations, cash flows and financial condition, as well as our ability to make distributions, could be impacted by the
following:
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our debt level and debt agreements, or increases in interest rates;
the credit and risk profile of our general partner and its owners; and
a downgrade of our credit ratings.
Capital Projects and Future Growth. Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the
following:
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failure to make acquisitions on economically acceptable terms, or to successfully integrate acquired assets;
failure to secure debt and equity financing for capital projects on acceptable terms, including as a result of recent increases in cost of capital resulting
from changes in monetary policy by the Federal Reserve and/or changes in financial institutions’ policies or practices concerning businesses linked to
fossil fuels;
any increased costs or reduced demand for crude oil and natural gas as a result of the Inflation Reduction Act of 2022 (“IRA 2022”) or otherwise;
failure to construct new pipelines or to do so efficiently;
failure to execute our growth strategy due to increased competition within any of our core businesses; and
failure to attract and retain qualified employees; and
failure of the liquefaction project to secure long-term contractual arrangements or necessary approvals.
Regulatory Matters. Our business, results of operations, cash flows, financial condition, and future growth could be impacted by the following:
•
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increased regulation of hydraulic fracturing or produced water disposal;
legal or regulatory actions related to the Dakota Access Pipeline;
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•
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laws, regulations and policies governing the rates, terms and conditions of our services;
failure to recover the full amount of increases in the costs of our pipeline operations;
imposition of regulation on assets not previously subject to regulation;
costs and liabilities resulting from performance of pipeline integrity programs and related repairs;
new or more stringent pipeline safety controls or enforcement of legal requirements;
costs and liabilities associated with environmental and worker health and safety laws and regulations;
climate change legislation or regulations restricting emissions of GHGs, limiting oil and gas leases on federal lands, discouraging oil and gas
development or otherwise increasing our or our customers’ costs;
increased attention to environmental, social, and governance (“ESG”) matters and conservation measures;
regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder;
deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-response and
decommissioning plans, and related developments; and
laws and regulations governing the specifications of products that we store and transport.
Risks Relating to Our Partnership Structure
Cash Distributions to Unitholders. Our cash distributions could be impacted by the following:
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our general partner’s absolute discretion in issuing an unlimited number of limited partner interests or other classes of equity without the consent of our
Unitholders;
cash distributions are not guaranteed and may fluctuate with our performance and other external factors;
limitations on available cash that are imposed by our distribution policy;
our general partner’s absolute discretion in determining the level of cash reserves; and
unitholders’ potential liability to repay distributions.
Our General Partner. Our stakeholders could be impacted by risks related to our general partner, including:
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transfer of control of our general partner to a third party without unitholder consent;
the rights of the majority owner of our general partner that protect him against dilution; and
substantial cost reimbursements due to our general partner.
Our Subsidiaries. Risks that are unique to our subsidiaries and/or our relationship to our subsidiaries could reduce our subsidiaries’ cash available for
distributions to us, including:
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the potential issuance of additional common units by Sunoco LP or USAC;
a significant decrease in demand for or the price of motor fuel in the areas Sunoco LP serves;
disruptions in Sunoco LP’s operations due to dangers inherent in motor fuel transportation;
seasonal industry trends, which may cause Sunoco LP’s operating costs to fluctuate;
adverse publicity for Sunoco LP resulting from negative events or developments;
increased costs to retain necessary land use, which could disrupt Sunoco LP’s operations; and
federal, state and local laws and regulations that govern the industries in which our subsidiaries operate.
Risks Related to Conflicts of Interest. Our stakeholders could be impacted by conflicts of interest, including:
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our general partner may favor its own interests to the detriment of our Unitholders;
fiduciary duties owed to Sunoco LP, USAC and their respective unitholders by their general partners; and
potential conflicts of interest faced by directors and officers in managing our business.
Tax Risks. Our stakeholders could be impacted by tax risks, including:
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our tax treatment depends on our status as a partnership for federal income tax purposes, and not being subject to a material amount of entity-level
taxation;
our cash available for distribution to Unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the IRS
treating us as a corporation or legislative, judicial or administrative changes, and may also be reduced by any audit adjustments if imposed directly on
the partnership;
even if Unitholders do not receive any cash distributions from us, Unitholders will be required to pay taxes on their share of our taxable income;
a Unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we
take;
tax-exempt entities and non-U.S. Unitholders face unique tax issues from owning our units that may result in adverse tax consequences to them; and
the treatment of Energy Transfer Preferred Units is uncertain and distributions on Energy Transfer Preferred Units (other than Series I Preferred Units)
may not be eligible for the 20% deduction for qualified publicly traded partnership income.
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Risk Factor Discussion
The following discussion provides additional information regarding each of our risk factors listed above. In addition, Sunoco LP and USAC file Annual
Reports on Form 10-K that include risk factors that can be reviewed for further information.
Risk Relating to the Partnership’s Business
Results of Operations and Financial Condition
Our cash flow depends primarily on the cash distributions we receive from our subsidiaries, as well as our partnership interests in Sunoco LP and USAC,
including the IDRs in Sunoco LP and, therefore, our cash flow is dependent upon the ability of our subsidiaries, Sunoco LP and USAC to make
distributions in respect of those partnership interests.
We do not have any significant assets other than our interests in our subsidiaries. As a result, our cash flow depends on the performance of our subsidiaries,
including Sunoco LP and USAC, and their ability to make cash distributions, which is dependent on the results of operations, cash flows and financial
condition of our subsidiaries, including Sunoco LP and USAC.
The amount of cash that our subsidiaries distribute to us each quarter depends upon the amount of cash generated from our subsidiaries’ operations, which
will fluctuate from quarter to quarter and will depend upon, among other things:
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the amount of natural gas, NGLs, crude oil and refined products transported through our subsidiaries’ pipelines;
the level of throughput in processing and treating operations;
the fees charged and the margins realized by our subsidiaries, including Sunoco LP and USAC, for their services;
the price of natural gas, NGLs, crude oil and refined products;
the relationship between natural gas, NGL and crude oil prices;
the weather in their respective operating areas;
the level of competition from other midstream, transportation and storage and retail marketing companies and other energy providers;
the level of their respective operating costs and maintenance and integrity capital expenditures;
the tax profile on any blocker entities treated as corporations for federal income tax purposes that are owned by any of our subsidiaries;
prevailing economic conditions; and
the level and results of their respective derivative activities.
In addition, the actual amount of cash that our subsidiaries, including Sunoco LP and USAC, will have available for distribution will also depend on other
factors, such as:
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the level of capital expenditures they make;
the level of costs related to litigation and regulatory compliance matters;
the cost of acquisitions, if any;
the levels of any margin calls that result from changes in commodity prices;
debt service requirements;
fluctuations in working capital needs;
their ability to borrow under their respective revolving credit facilities;
their ability to access capital markets;
restrictions on distributions contained in their respective debt agreements; and
the amount, if any, of cash reserves established by the board of directors and their respective general partners in their discretion for the proper conduct
of their respective businesses.
Energy Transfer does not have any control over many of these factors, including the level of cash reserves established by the board of directors.
Accordingly, we cannot guarantee that our subsidiaries, including Sunoco LP and USAC, will have sufficient available cash to pay a specific level of cash
distributions to their respective partners.
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Furthermore, Unitholders should be aware that the amount of cash that our subsidiaries have available for distribution depends primarily upon cash flow
and is not solely a function of profitability, which is affected by non-cash items. As a result, our subsidiaries may declare and/or pay cash distributions
during periods when they record net losses.
Income from our midstream, transportation, terminalling and storage operations is exposed to risks due to fluctuations in the demand for and price of
natural gas, NGLs, crude oil and refined products that are beyond our control.
The prices for natural gas, NGLs, crude oil and refined products reflect market demand that fluctuates with changes in global and United States economic
conditions and other factors, including:
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the level of domestic natural gas, NGL, refined products and oil production;
the level of natural gas, NGL, refined products and oil imports and exports, including liquefied natural gas;
actions taken by natural gas and oil producing nations;
instability or other events affecting natural gas and oil producing nations;
the impact of weather, geopolitical events such as the armed conflict in Ukraine and political instability in the Middle East, public health crises, and
other events of nature on the demand for natural gas, NGLs, refined products and oil;
the availability of storage, terminal and transportation systems, and refining, processing and treating facilities;
the price, availability and marketing of competitive fuels;
supply chain disruptions and inflation;
the demand for electricity;
activities by non-governmental organizations to limit certain sources of funding for the energy sector or restrict the exploration, development and
production of oil and natural gas and related products;
rising interest rates and slowing economic growth;
the cost of capital needed to maintain or increase production levels and to construct and expand facilities;
the impact of energy conservation and fuel efficiency efforts; and
the extent of governmental regulations, taxation, fees and duties.
In the past, the prices of natural gas, NGLs, refined products and oil have been extremely volatile, and we expect this volatility to continue.
Any loss of business from existing customers or our inability to attract new customers due to a decline in demand for natural gas, NGLs, refined products
or oil could have a material adverse effect on our revenues and results of operations. In addition, significant price fluctuations for natural gas, NGL, refined
products and oil commodities could materially affect our profitability.
Our business could be negatively impacted by inflationary pressures which may decrease our operating margins and increase working capital investments
required to operate our business.
The U.S. inflation rate steadily rose in 2021 and into 2022 before eventually declining throughout 2023. A sustained increase in inflation may continue to
increase our costs for labor, services, and materials, which, in turn, could cause our operating costs and capital expenditures to increase. Further, our
producer suppliers and customers face inflationary pressures and resulting impacts, such as the tight labor market, availability of drilling and hydraulic
fracturing equipment, and supply chain disruptions, which could increase the cost of production which in turn may limit the level of drilling activity in the
regions in which we operate. Our throughput volumes may be impacted if producers are constrained. The rate and scope of these various inflationary
factors may increase our operating costs and capital expenditures materially, which may not be readily recoverable in the prices of our services and may
have an adverse effect on our results of operations and financial condition.
Additionally, the Federal Reserve and other central banks have implemented policies in an effort to curb inflationary pressure on the costs of goods and
services across the U.S., including the significant increases in prevailing interest rates that occurred during 2022 and 2023 as a result of the 525 aggregate
basis point increase in the federal funds rate, and the associated macroeconomic impact on slowdown in economic growth could negatively impact our
business. While the Federal Reserve indicated in December 2023 that it may reduce benchmark interest rates in 2024, the continuation of rates at the
current level could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt
the financial and operating results of our business.
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An impairment of goodwill and intangible assets could reduce our earnings.
As of December 31, 2023, our consolidated balance sheet reflected $4.02 billion of goodwill and $6.24 billion of intangible assets. Goodwill is recorded
when the purchase price of a business exceeds the fair value of the tangible and separately measurable intangible net assets. Accounting principles
generally accepted in the United States require us to test goodwill for impairment on an annual basis or when events or circumstances occur, indicating that
goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we
would be required to take an immediate charge to earnings with a correlative effect on partners’ capital and balance sheet leverage as measured by debt to
total capitalization.
We depend on certain key producers for our supply of natural gas and the loss of any of these key producers could adversely affect our financial results.
Certain producers who are connected to our systems represent a material source of our supply of natural gas. We are not the only option available to these
producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they
supply us, we would be adversely affected unless we were able to acquire comparable supplies of natural gas from other producers.
Our intrastate transportation and storage and interstate transportation and storage operations depend on key customers to transport natural gas through
our pipelines and the pipelines of our joint ventures.
During 2023, two customers accounted for approximately 36% of our intrastate transportation and storage revenues. During 2023, four customers
collectively accounted for 30% of our interstate transportation and storage revenues.
Certain of our joint ventures also depend on key customers. Citrus has long-term agreements with its top two customers which accounted for 52% of its
2023 revenue. For the Trans-Pecos and Comanche Trail pipelines, a single customer is the primary shipper.
The failure of the major shippers on our and our joint ventures’ intrastate and interstate transportation and storage pipelines to fulfill their contractual
obligations could have a material adverse effect on our cash flow and results of operations if we or our joint ventures were unable to replace these
customers under arrangements that provide similar economic benefits as these existing contracts.
We may be unable to retain or replace existing midstream, transportation, terminalling and storage customers or volumes due to declining demand or
increased competition in crude oil, refined products, natural gas and NGL markets, which would reduce our revenues and limit our future profitability.
The retention or replacement of existing customers and the volume of services that we provide at rates sufficient to maintain or increase current revenues
and cash flows depends on a number of factors beyond our control, including the price of and demand for crude oil, refined products, natural gas and NGLs
in the markets we serve and competition from other service providers.
A significant portion of our sales of natural gas are to industrial customers and utilities. As a consequence of the volatility of natural gas prices and
increased competition in the industry and other factors, industrial customers, utilities and other gas customers are increasingly reluctant to enter into long-
term purchase contracts. Many customers purchase natural gas from more than one supplier and have the ability to change suppliers at any time. Some of
these customers also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are
many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in natural gas sales
markets primarily on the basis of price.
We also receive a substantial portion of our revenues by providing natural gas gathering, processing, treating, transportation and storage services. While a
substantial portion of our services are sold under long-term contracts for reserved service, we also provide service on an unreserved or short-term basis.
Demand for our services may be substantially reduced due to changing market prices. Declining prices may result in lower rates of natural gas production
resulting in less use of services, while rising prices may diminish consumer demand and also limit the use of services. In addition, our competitors may
attract our customers’ business. If demand declines or competition increases, we may not be able to sustain existing levels of unreserved service or renew
or extend long-term contracts as they expire or we may reduce our rates to meet competitive pressures.
Revenue from our NGL transportation systems and refined products storage is also exposed to risks due to fluctuations in demand for transportation and
storage service as a result of unfavorable commodity prices, competition from nearby pipelines, and other factors. We receive substantially all of our
transportation revenues through dedicated contracts under which the customer agrees to deliver the total output from particular processing plants that are
connected only to our transportation
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system. Reduction in demand for natural gas or NGLs due to unfavorable prices or other factors, however, may result lower rates of production under
dedicated contracts and lower demand for our services. In addition, our refined products storage revenues are primarily derived from fixed capacity
arrangements between us and our customers, a portion of our revenue is derived from fungible storage and throughput arrangements, under which our
revenue is more dependent upon demand for storage from our customers.
The volume of crude oil and refined products transported through our crude oil and refined products pipelines and terminal facilities depends on the
availability of attractively priced crude oil and refined products in the areas serviced by our assets. A period of sustained price reductions for crude oil or
refined products could lead to a decline in drilling activity, production and refining of crude oil or import levels in these areas. A period of sustained
increases in the price of crude oil or refined products supplied from or delivered to any of these areas could materially reduce demand for crude oil or
refined products in these areas. In either case, the volumes of crude oil or refined products transported in our crude oil and refined products pipelines and
terminal facilities could decline.
The loss of existing customers by our midstream, transportation, terminalling and storage facilities or a reduction in the volume of the services our
customers purchase from us, or our inability to attract new customers and service volumes would negatively affect our revenues, be detrimental to our
growth, and adversely affect our results of operations.
We and our subsidiaries, including Sunoco LP and USAC, are exposed to the credit risk of our customers and derivative counterparties, and an increase in
the nonpayment and nonperformance by our customers or derivative counterparties could reduce our ability to make distributions to our Unitholders.
We, Sunoco LP and USAC are subject to risks of loss resulting from nonpayment or nonperformance by our, Sunoco LP’s and USAC’s customers.
Commodity price volatility and/or the tightening of credit in the financial markets may make it more difficult for customers to obtain financing and,
depending on the degree to which this occurs, there may be a material increase in the nonpayment and nonperformance by our customers. In addition, our
risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms
of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any material nonpayment or
nonperformance by our customers or our derivative counterparties could reduce our ability to make distributions to our Unitholders. Any substantial
increase in the nonpayment and nonperformance by our customers could have a material effect on our, Sunoco LP’s and USAC’s results of operations and
operating cash flows.
Severe market disruptions could cause some of our counterparties to file for bankruptcy protection, in which case our existing contracts with those
counterparties may be rejected by the bankruptcy court. Following the request of one of our FERC-regulated natural gas pipelines, the FERC commenced a
proceeding to determine whether the public interest requires abrogation or modification of a firm transportation agreement with one of our shippers. By
order dated November 9, 2020, FERC held that the record did not support a finding that the public interest presently required abrogation or modification of
the subject firm transportation agreement. The shipper subsequently filed for bankruptcy. Thereafter, on July 19, 2022, the Fifth Circuit Court of Appeals
rejected FERC’s jurisdictional basis for its earlier public interest decision, vacated the November 9, 2020 order and a settlement has been reached regarding
the agreement in the underlying bankruptcy proceeding. We will attempt to remarket the subject capacity and, depending on the availability of alternatives
to our services, any resulting contracts may have terms that are less favorable to us than the former shipper’s contract.
The profitability of certain activities in our natural gas gathering, processing, transportation and storage operations are largely dependent upon natural
gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs.
For a portion of the natural gas gathered on our systems, we purchase natural gas from producers at the wellhead and then gather and deliver the natural gas
to pipelines where we typically resell the natural gas under various arrangements, including sales at index prices. Generally, the gross margins we realize
under these arrangements decrease in periods of low natural gas prices.
We also enter into percent-of-proceeds arrangements, keep-whole arrangements, and processing fee agreements pursuant to which we agree to gather and
process natural gas received from the producers.
Under percent-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon
percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon
percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements,
our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs
could have an adverse effect on our revenues and results of operations.
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Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations at market prices. Because the
extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market
prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our gross margins
generally decrease when the price of natural gas increases relative to the price of NGLs.
When we process the gas for a fee under processing fee agreements, we may guarantee recoveries to the producer. If recoveries are less than those
guaranteed to the producer, we may suffer a loss by having to supply liquids or its cash equivalent to keep the producer whole.
We also receive fees and retain gas in kind from our natural gas transportation and storage customers. Our fuel retention fees and the value of gas that we
retain in kind are directly affected by changes in natural gas prices. Decreases in natural gas prices tend to decrease our fuel retention fees and the value of
retained gas.
In addition, we receive revenue from our off-gas processing and fractionating system in south Louisiana primarily through customer agreements that are a
combination of keep-whole and percent-of-proceeds arrangements, as well as from transportation and fractionation fees. Consequently, a large portion of
our off-gas processing and fractionation revenue is exposed to risks due to fluctuations in commodity prices. In addition, a decline in NGL prices could
cause a decrease in demand for our off-gas processing and fractionation services and could have an adverse effect on our results of operations.
Our midstream facilities and transportation pipelines provide services related to natural gas wells that experience production declines over time, which we
may not be able to replace with natural gas production from newly drilled wells in the same natural gas basins or in other new natural gas producing
areas.
In order to maintain or increase throughput levels on our gathering systems and transportation pipeline systems and asset utilization rates at our treating and
processing plants, we must continually contract for new natural gas supplies and natural gas transportation services.
A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells
that experience declining production over time. Our gas transportation pipelines are also dependent upon natural gas production in areas served by our
gathering systems or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. We may not be
able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of
natural gas throughput on our transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering
systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and
production of natural gas near our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect.
We have no control over the level of drilling activity in our areas of operation, the amount of reserves underlying the wells and the rate at which production
from a well will decline. In addition, we have no control over producers or their production and contracting decisions.
While a substantial portion of our services are provided under long-term contracts for reserved service, we also provide service on an unreserved basis. The
reserves available through the supply basins connected to our gathering, processing, treating, transportation and storage facilities may decline and may not
be replaced by other sources of supply. A decrease in development or production activity could cause a decrease in the volume of unreserved services we
provide and a decrease in the number and volume of our contracts for reserved transportation service over the long run, which in each case would adversely
affect our revenues and results of operations.
If we are unable to replace any significant volume declines with additional volumes from other sources, our results of operations and cash flows could be
materially and adversely affected.
Our revenues depend on our customers’ ability to use our pipelines and third-party pipelines over which we have no control.
Our natural gas transportation, storage and NGL businesses depend, in part, on our customers’ ability to obtain access to pipelines to deliver gas to us and
receive gas from us. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on our pipelines or third-party
pipelines due to testing, line repair, reduced operating pressures, or other causes or adverse change in terms and conditions of service could have a material
adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our pipelines and facilities and a corresponding material
adverse effect on our transportation and storage revenues. In addition, the rates charged by interconnected pipelines for transportation to and from our
facilities affect the utilization and value of our storage services. Significant changes in the rates charged by those pipelines or the rates charged by other
pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.
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Shippers using our oil pipelines and terminals are also dependent upon our pipelines and connections to third-party pipelines to receive and deliver crude
oil and products. Any interruptions or reduction in the capabilities of these pipelines due to testing, line repair, reduced operating pressures, or other causes
could result in reduced volumes transported in our pipelines or through our terminals. Similarly, if additional shippers begin transporting volume over
interconnecting oil pipelines, the allocations of pipeline capacity to our existing shippers on these interconnecting pipelines could be reduced, which also
could reduce volumes transported in its pipelines or through our terminals. Allocation reductions of this nature are not infrequent and are beyond our
control. Any such interruptions or allocation reductions that, individually or in the aggregate, are material or continue for a sustained period of time could
have a material adverse effect on our results of operations, financial position, or cash flows.
The inability to continue to access lands owned by third parties could adversely affect our ability to operate and our financial results.
Our ability to operate our pipeline systems on certain lands owned by third parties will depend on our success in maintaining existing rights-of-way and
obtaining new rights-of-way on those lands. We are parties to rights-of-way agreements, permits and licenses authorizing land use with numerous parties,
including, private land owners, governmental entities, Native American tribes, rail carriers, public utilities and others. For more information, see our
regulatory disclosure titled “Indigenous Protections.” Our ability to secure extensions of existing agreements, permits and licenses is essential to our
continuing business operations, and securing additional rights-of-way will be critical to our ability to pursue expansion projects. We cannot provide any
assurance that we will be able to maintain access to existing rights-of-way upon the expiration of the current grants, that all of the rights-of-way will be
obtained in a timely fashion or that we will acquire new rights-of-way as needed.
Further, whether we have the power of eminent domain for our pipelines varies from state to state, depending upon the type of pipeline and the laws of the
particular state and the ownership of the land to which we seek access. When we exercise eminent down rights or negotiate private agreements cases, we
must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. The inability
to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our
pipelines are located. For example, following a decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very
small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Indian landowner, bars condemnation of any
interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where existing pipeline rights-of-way may soon
lapse or terminate serves as an additional impediment for pipeline operators. Any loss of rights with respect to our real property, through our inability to
renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to
make cash distributions to Unitholders.
Our storage operations are influenced by the overall forward market for crude oil and other products we store, and certain market conditions may
adversely affect our financial and operating results.
Our storage operations are influenced by the overall forward market for crude oil and other products we store. A contango market (meaning that the price
of crude oil or other products for future delivery is higher than the current price) is associated with greater demand for storage capacity, because a party can
simultaneously purchase crude oil or other products at current prices for storage and sell at higher prices for future delivery. A backwardated market
(meaning that the price of crude oil or other products for future delivery is lower than the current price) is associated with lower demand for storage
capacity because a party can capture a premium for prompt delivery of crude oil or other products rather than storing it for future sale. A prolonged
backwardated market, or other adverse market conditions, could have an adverse impact on its ability to negotiate favorable prices under new or renewing
storage contracts, which could have an adverse impact on our storage revenues. As a result, the overall forward market for crude oil or other products may
have an adverse effect on our financial condition or results of operations.
Competition for water resources or limitations on water usage for hydraulic fracturing could disrupt crude oil and natural gas production from shale
formations.
Hydraulic fracturing is the process of creating or expanding cracks by pumping water, sand and chemicals under high pressure into an underground
formation in order to increase the productivity of crude oil and natural gas wells. Water used in the process is generally fresh water, recycled produced
water or salt water. There is competition for fresh water from municipalities, farmers, ranchers and industrial users. In addition, the available supply of
fresh water can also be reduced directly by drought. Prolonged drought conditions increase the intensity of competition for fresh water. Limitations on oil
and gas producers’ access to fresh water may restrict their ability to use hydraulic fracturing and could reduce new production. Such disruptions could
potentially have a material adverse impact on our financial condition or results of operations.
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A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our
operations and otherwise materially adversely affect our cash flow.
Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise
materially adversely affect our cash flow. For example, natural gas pipeline and other facilities operate at high pressures. Virtually all of our operations are
exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.
If one or more facilities that are owned by us, or that deliver natural gas or other products to us, are damaged by severe weather or any other disaster,
accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other
facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to
people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any
event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce
our cash available for paying distributions to Unitholders.
As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain
insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies
or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully
insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not
be paid in a timely manner and may be insufficient if such an event were to occur.
Terrorist attacks aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.
The United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist
organizations. Some of our facilities are subject to standards and procedures required by the Chemical Facility Anti-Terrorism Standards. We believe we
are in compliance with all material requirements; however, such compliance may not prevent a terrorist attack from causing material damage to our
facilities or pipelines. Any such terrorist attack on our facilities or pipelines, those of our customers, or in some cases, those of other pipelines could have a
material adverse effect on our business, financial condition and results of operations.
Our business could be affected adversely by union disputes and strikes or work stoppages by unionized employees.
As of December 31, 2023, approximately 10% of our workforce is covered by a number of collective bargaining agreements with various terms and dates
of expiration. There can be no assurances that we will not experience a work stoppage in the future as a result of labor disagreements. Any work stoppage
could, depending on the affected operations and the length of the work stoppage, have a material adverse effect on our business, financial position, results
of operations or cash flows.
Cybersecurity attacks, data breaches and other disruptions affecting us, or our service providers, could materially and adversely affect our business,
operations, reputation, and financial results.
The security and integrity of our information technology infrastructure and physical assets are critical to our business and our ability to perform day-to-day
operations and deliver services. In addition, in the ordinary course of our business, we collect, process, transmit and store sensitive data, including
intellectual property, our proprietary business information and that of our customers, suppliers and business partners, as well as personally identifiable
information, in our data centers and on our networks. We also engage third parties, such as service providers and vendors, who provide a broad array of
software, technologies, tools, and other products, services and functions (e.g., human resources, finance, data transmission, communications, risk,
compliance, among others) that enable us to conduct, monitor and/or protect our business, operations, systems and data assets.
Our information technology and infrastructure, physical assets and data, may be vulnerable to unauthorized access, computer viruses, malicious attacks and
other events (e.g., distributed denial of service attacks, ransomware attacks) that are beyond our control. These events can result from malfeasance by
external parties, such as hackers, or due to human error or malfeasance by our or our service providers’ employees and contractors (e.g., due to social
engineering or phishing attacks). In addition, work-from-home arrangements may present additional operational and cybersecurity risks to our information
technology infrastructure and physical assets.
We and certain of our service providers have, from time to time, been subject to cyber attacks and security incidents. The frequency and magnitude of cyber
attacks is increasing and attackers are becoming more sophisticated. Cyber attacks,
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including, but not limited to, malicious software, surveillance, credential stuffing, spear phishing, social engineering, use of deepfakes (i.e., highly realistic
synthetic media generated by artificial intelligence), attempts to gain unauthorized access to data, and other electronic security breaches that could lead to
disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data, are evolving. We may be
unable to anticipate, detect or prevent future attacks, particularly as the methodologies used by attackers change frequently or are not recognized until
launched, and we may be unable to investigate or remediate incidents because attackers are increasingly using techniques and tools designed to circumvent
controls, to avoid detection, and to remove or obfuscate forensic evidence.
Breaches of our information technology infrastructure or physical assets, or other disruptions, could result in damage to our assets, safety incidents, damage
to the environment, potential liability or the loss of contracts, data loss or corruption, misdirected wire transfers, an inability to maintain our books and
records or an inability to prevent environmental damage, any or all of which could, in turn, have a material adverse effect on our operations, financial
position and results of operations. A successful cyber attack or other security incident could compromise our networks and the information stored there
could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or loss could result in legal claims or proceedings, significant litigation
costs, regulatory investigations and enforcement, penalties and fines, increased costs for system remediation and compliance requirements, disruption of
our operations, damage to our reputation, or loss of confidence in our products and services, any or all of which could have a material adverse effect on our
business and results. We may be required to invest significant additional resources to comply with evolving cybersecurity and data privacy laws or
regulations and to modify and enhance our information security and controls, and to investigate and remediate any security vulnerabilities. Any losses,
costs or liabilities may not be covered by, or may exceed the coverage limits of, any or all of our applicable insurance policies.
Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.
Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including
our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer
systems. If a key system was to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results
could be affected adversely. Our systems could be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or
similar event. We have a formal disaster recovery plan in place, but this plan may not entirely prevent delays or other complications that could arise from
an information systems failure. Our business interruption insurance may not compensate us adequately for losses that may occur.
Product liability claims and litigation could adversely affect our business and results of operations.
Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers
based upon claims for injuries caused by the use of or exposure to various products. There can be no assurance that product liability claims against us
would not have a material adverse effect on our business or results of operations.
Along with other refiners, manufacturers and sellers of gasoline, ETC Sunoco is a defendant in numerous lawsuits that allege MTBE contamination in
groundwater. Plaintiffs, who include water purveyors and municipalities responsible for supplying drinking water and private well owners, are seeking
compensatory damages (and in some cases injunctive relief, punitive damages and attorneys’ fees) for claims relating to the alleged manufacture and
distribution of a defective product (MTBE-containing gasoline) that contaminates groundwater, and general allegations of product liability, nuisance,
trespass, negligence, violation of environmental laws and deceptive business practices. There has been insufficient information developed about the
plaintiffs’ legal theories or the facts that would be relevant to an analysis of the ultimate liability to ETC Sunoco. An adverse determination of liability
related to these allegations or other product liability claims against ETC Sunoco could have a material adverse effect on our business or results of
operations.
We do not control, and therefore may not be able to cause or prevent certain actions by, certain of our joint ventures.
Certain of our operations are conducted through joint ventures, some of which have their own governing boards. With respect to our joint ventures, we
share ownership and management responsibilities with partners that may not share our goals and objectives. Consequently, it may be difficult or impossible
for us to cause the joint venture entity to take actions that we believe would be in their or the joint venture’s best interests. Likewise, we may be unable to
prevent actions of the joint venture. Differences in views among joint venture partners may result in delayed decisions or failures to agree on major matters,
such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to
agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed
decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations.
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The use of derivative financial instruments could result in material financial losses by us.
From time to time, we and/or our subsidiaries have sought to reduce our exposure to fluctuations in commodity prices and interest rates by using derivative
financial instruments and other risk management mechanisms and by our trading, marketing and/or system optimization activities. To the extent that we
hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to
change in our favor.
The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions that are effective economically
(whether to mitigate our exposure to fluctuations in commodity prices, or to balance our exposure to fixed and variable interest rates), these transactions
may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these
hedges, even when there is no underlying economic impact at that point. It is also not always possible for us to engage in a hedging transaction that
completely mitigates our exposure to commodity prices. Our consolidated financial statements may reflect a gain or loss arising from an exposure to
commodity prices for which we are unable to enter into a completely effective hedge.
In addition, our derivatives activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform
its obligations under the derivative arrangement, the hedge is imperfect, commodity prices move unfavorably related to our physical or financial positions
or hedging policies and procedures are not followed.
Increasing levels of congestion in the Houston Ship Channel could result in a diversion of business to less busy ports.
Our Gulf Coast facilities are strategically situated on prime real estate located in the Houston Ship Channel, which is in close proximity to both supply
sources and demand sources. In recent years, the success of the Port of Houston has led to an increase in vessel traffic driven in part by the growing
overseas demand for U.S. crude, gasoline, liquefied natural gas and petrochemicals and in part by the Port of Houston’s recent decision to accept large
container vessels, which can restrict the flow of other cargo. Increasing congestion in the Port of Houston, which is currently the busiest port in the U.S. by
waterborne tonnage and which has increased volumes in each of the last two years, could cause our customers or potential customers to divert their
business to smaller ports in the Gulf of Mexico, which could result in lower utilization of our facilities.
The costs of providing pension and other postretirement health care benefits and related funding requirements are subject to changes in pension fund
values, changing demographics and fluctuating actuarial assumptions and may have a material adverse effect on our financial results.
Certain of our subsidiaries provide pension plan and other postretirement healthcare benefits to certain of their employees. The costs of providing pension
and other postretirement health care benefits and related funding requirements are subject to changes in pension and other postretirement fund values,
changing demographics and fluctuating actuarial assumptions that may have a material adverse effect on the Partnership’s future consolidated financial
results. While certain of the costs incurred in providing such pension and other postretirement healthcare benefits are recovered through the rates charged
by the Partnership’s regulated businesses, the Partnership’s subsidiaries may not recover all of the costs and those rates are generally not immediately
responsive to current market conditions or funding requirements. Additionally, if the current cost recovery mechanisms are changed or eliminated, the
impact of these benefits on operating results could significantly increase.
Mergers among customers and competitors could result in lower volumes being shipped on our pipelines or products stored in or distributed through our
terminals, or reduced crude oil marketing margins or volumes.
Mergers between existing customers could provide strong economic incentives for the combined entities to utilize their existing systems instead of our
systems in those markets where the systems compete. As a result, we could lose some or all of the volumes and associated revenues from these customers
and could experience difficulty in replacing those lost volumes and revenues, which could materially and adversely affect our results of operations,
financial position, or cash flows.
Fraudulent activity or misuse of proprietary data involving our outsourcing partners could expose us to additional liability.
We utilize both affiliated entities and third parties in the processing of our information and data. Breaches of security measures or the accidental loss,
inadvertent disclosure or unapproved dissemination of proprietary information, or sensitive or confidential data about us or our customers, including the
potential loss or disclosure of such information or data as a result of fraud or other forms of deception, could expose us to a risk of loss, or misuse of this
information, result in litigation and potential liability, lead to reputational damage, increase our compliance costs, or otherwise harm our business.
Our trucking fleet operations are subject to the Federal Motor Carrier Safety Regulations which are enacted, reviewed and amended by the Federal Motor
Carrier Safety Administration (“FMCSA”). Our fleet currently has a “satisfactory” safety
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rating; however, if our safety rating were downgraded to “unsatisfactory,” our business and results of operations could be adversely affected.
All federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance Safety
Accountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on violations observed during roadside inspections as
opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of
comparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is a
progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will
implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the
revocation of its operating authority by the FMCSA could have an adverse effect on our business, results of operations and financial condition.
Indebtedness
Our debt level and debt agreements may limit our ability to make distributions to Unitholders and may limit our future financial and operating flexibility.
As of December 31, 2023, we had approximately $52.39 billion of consolidated debt, excluding the debt of our unconsolidated joint ventures. Our level of
indebtedness affects our operations in several ways, including, among other things:
•
•
•
a significant portion of our and our subsidiaries’ cash flow from operations will be dedicated to the payment of principal and interest on outstanding
debt and will not be available for other purposes, including payment of distributions;
covenants contained in our and our subsidiaries’ existing debt agreements require us and them, as applicable, to meet financial tests that may adversely
affect our flexibility in planning for and reacting to changes in our business;
our and our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate
or limited liability company purposes, as applicable, may be limited;
• we may be at a competitive disadvantage relative to similar companies that have less debt;
• we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level; and
•
failure by us or our subsidiaries to comply with the various restrictive covenants of our respective debt agreements could negatively impact our ability
to incur additional debt, including our ability to utilize the available capacity under our revolving credit facility, and our ability to pay our distributions.
The debt level and debt agreements of our subsidiaries, including Sunoco LP and USAC, may limit the distributions we receive from these subsidiaries, as
well as our future financial and operating flexibility.
Our subsidiaries’ levels of indebtedness affect their operations in several ways, including, among other things:
•
•
•
•
•
•
a significant portion of our subsidiaries’ cash flows from operations will be dedicated to the payment of principal and interest on outstanding debt and
will not be available for other purposes, including payment of distributions to us;
covenants contained in our subsidiaries’ existing debt agreements require the respective subsidiaries, as applicable, to meet financial tests that may
adversely affect their flexibility in planning for and reacting to changes in their respective businesses;
our subsidiaries’ ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership, corporate or
limited liability company purposes, as applicable, may be limited;
our subsidiaries may be at a competitive disadvantage relative to similar companies that have less debt;
our subsidiaries may be more vulnerable to adverse economic and industry conditions as a result of their debt levels;
failure by our subsidiaries to comply with the various restrictive covenants of the respective debt agreements could negatively impact the respective
subsidiaries’ ability to incur additional debt, including their ability to utilize the available capacity under their revolving credit facilities, and to pay
distributions to us and their unitholders.
As a result of Sunoco LP’s previously announced acquisition of NuStar, which is expected to close in the second quarter of 2024, Sunoco LP expects to
assume NuStar’s debt and issue additional debt, aggregating approximately $4.2 billion. This additional debt may accelerate any of the risks discussed
above.
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We do not have the same flexibility as other types of organizations to accumulate cash, which may limit cash available to service our debt or to repay debt
at maturity.
Unlike a corporation, our Partnership Agreement requires us to distribute, on a quarterly basis, 100% of our Available Cash (as defined in our Partnership
Agreement) to our Unitholders of record and our general partner. Available Cash is generally all of our cash on hand as of the end of a quarter, adjusted for
cash distributions and net changes to reserves. Our general partner will determine the amount and timing of such distributions and has broad discretion to
establish and make additions to our reserves or the reserves of our operating subsidiaries in amounts it determines in its reasonable discretion to be
necessary or appropriate:
•
•
•
to provide for the proper conduct of our business and the businesses of our operating subsidiaries (including reserves for future capital expenditures
and for our anticipated future credit needs);
to provide funds for distributions to our Unitholders and our general partner for any one or more of the next four calendar quarters; or
to comply with applicable law or any of our loan or other agreements.
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
In addition to our exposure to commodity prices, we have significant exposure to changes in interest rates, including the significant increases in prevailing
interest rates as a result of changes in federal monetary and fiscal policy. Approximately $3.29 billion of our consolidated debt as of December 31, 2023
bears interest at variable interest rates and the remainder bears interest at fixed rates. To the extent that we have debt with floating interest rates, our results
of operations, cash flows and financial condition could be materially adversely affected by increases in interest rates.
An increase in interest rates could impact demand for our storage capacity.
There is a financing cost for a storage capacity user to own crude oil while it is stored. That financing cost is impacted by the cost of capital or interest rate
incurred by the storage user, in addition to the commodity cost of the crude oil in inventory. Absent other factors, a higher financing cost adversely impacts
the economics of storing crude oil for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage
capacity independent of other market factors.
An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity
investments such as our Common Units. Any such reduction in demand for our Common Units resulting from other more attractive investment
opportunities may cause the trading price of our Common Units to decline.
A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit
ratings is under the control of independent third parties.
A downgrade of our credit ratings may increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties,
negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit
ratings and other disruptions. Such disruptions could include:
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economic downturns;
deteriorating capital market conditions;
declining market prices for crude oil, natural gas, NGLs and other commodities;
terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to,
business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry
sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold
investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will
maintain our current credit ratings.
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Capital Projects and Future Growth
If we and our subsidiaries do not make acquisitions on economically acceptable terms, our future growth could be limited.
Our results of operations and our ability to grow and to make distributions to Unitholders will depend in part on our ability to make acquisitions that are
accretive to our distributable cash flow per unit.
We may be unable to make accretive acquisitions for any of the following reasons, among others:
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because we are unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
because we are unable to raise financing for such acquisitions on economically acceptable terms;
because of recent heightened antitrust focus in the energy industry creating potential risk, expense and delays in connection with prospective
acquisitions and consolidations; or
because we are outbid by competitors, particularly as a trend of consolidation within the energy industry continues, some of which are substantially
larger than us and have greater financial resources and lower costs of capital then we do.
Furthermore, even if we consummate acquisitions that we believe will be accretive, those acquisitions may in fact adversely affect our results of operations
or result in a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that we may:
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fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;
decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;
encounter difficulties operating in new geographic areas or new lines of business;
incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which
the indemnity is inadequate;
be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;
less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns; or
incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
If we consummate future acquisitions, our capitalization and results of operations may change significantly. As we determine the application of our funds
and other resources, Unitholders will not have an opportunity to evaluate the economic, financial and other relevant information that we will consider.
Capital projects may require significant amounts of debt and equity financing, which may not be available to us on acceptable terms, or at all.
We may fund our growth capital expenditures, including any new pipeline construction projects and improvements or repairs to existing facilities that we
may undertake, with proceeds from sales of our debt and equity securities and borrowings under our revolving credit facility; however, we cannot be
certain that we will be able to issue our debt and equity securities on terms satisfactory to us, or at all. If we are required to seek alternative financing, the
terms of which may not be attractive to us, or to revise or cancel our expansion plans.
A significant increase in our indebtedness that is proportionately greater than our issuance of equity could negatively impact our and our subsidiaries’ credit
ratings or our ability to remain in compliance with the financial covenants under our revolving credit agreement, which could have a material adverse effect
on our financial condition, results of operations and cash flows.
The Inflation Reduction Act of 2022 could decrease demand for crude oil and natural gas and could impose new costs on our operations.
In August 2022, President Biden signed the IRA 2022, which contains hundreds of billions in incentives for the development of renewable energy, clean
hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. In addition, the IRA
2022 imposes the first-ever federal fee on the emission of GHGs through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to
impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum
and
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natural gas production categories. The methane emissions charge started in calendar year 2024 at $900 per ton of methane, increases to $1,200 in 2025, and
will be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. In addition, the multiple
incentives offered for various clean energy industries referenced above could decrease demand for crude oil and natural gas, increase our compliance and
operating costs and consequently adversely affect our business.
If we do not continue to construct new pipelines, our future growth could be limited.
Our results of operations and ability to grow and to increase distributable cash flow per unit will depend, in part, on our ability to construct pipelines that
are accretive to our distributable cash flow. We may be unable to construct pipelines that are accretive to distributable cash flow for any of the following
reasons, among others:
• we are unable to identify pipeline construction opportunities with favorable projected financial returns;
• we are unable to obtain necessary governmental approvals and contracts with qualified contractors and vendors on acceptable terms;
• we are unable to raise financing for our identified pipeline construction opportunities; or
• we are unable to secure sufficient transportation commitments from potential customers due to competition from other pipeline construction projects or
for other reasons.
Furthermore, even if we construct a pipeline that we believe will be accretive, the pipeline may in fact adversely affect our results of operations or results
from those projected prior to commencement of construction and other factors.
Expanding our business by constructing new pipelines and related facilities subjects us to risks.
One of the ways that we have grown our business is through the construction of additions to our existing gathering, compression, treating, processing and
transportation systems. The construction of new pipelines and related facilities (or the improvement and repair of existing facilities) involves numerous
regulatory, environmental, political and legal uncertainties beyond our control and requires the expenditure of significant amounts of capital that we will be
required to finance through borrowings, the issuance of additional equity or from operating cash flow. If we undertake these projects, they may not be
completed on schedule, at all, or at the budgeted cost. A variety of factors outside our control, such as weather, natural disasters and difficulties in obtaining
permits and rights-of-way or other regulatory approvals, as well as the performance by third-party contractors, may result in increased costs or delays in
construction. For example, in recent years, pipeline projects by many companies have been subject to several challenges by environmental groups, such as
challenges to agency reviews under the NEPA and to the USACE NWP program. Any changes to the USACE NWP program that exclude our projects from
coverage could require us to reroute pipeline projects, or seek individual permits that involve longer permitting timelines, leading to construction delays.
For more information on the NWP program, see our regulatory disclosure titled “Clean Water Act.” Separately, cost overruns or delays in completing a
project could have a material adverse effect on our results of operations and cash flows. Moreover, our revenues may not increase immediately following
the completion of a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, but we may not
materially increase our revenues until long after the project’s completion. In addition, the success of a pipeline construction project will likely depend upon
the level of oil and natural gas exploration and development drilling activity and the demand for pipeline transportation in the areas proposed to be serviced
by the project as well as our ability to obtain commitments from producers in the area to utilize the newly constructed pipelines. In this regard, we may
construct facilities to capture anticipated future growth in oil or natural gas production in a region in which such growth does not materialize. As a result,
new facilities may be unable to attract enough throughput or contracted capacity reservation commitments to achieve our expected investment return,
which could adversely affect our results of operations and financial condition.
The liquefaction project is dependent upon securing long-term contractual arrangements for the offtake of LNG on terms sufficient to support the financial
viability of the project.
Lake Charles LNG Export, our wholly owned subsidiary, is in the process of developing a liquefaction project at the site of our existing regasification
facility in Lake Charles, Louisiana. The project would utilize existing dock and storage facilities owned by us located on the Lake Charles site. The parties’
determination as to the feasibility of the project will be particularly dependent upon the prospects for securing long-term contractual arrangements for the
offtake of LNG which in turn will be dependent upon supply and demand factors affecting the price of LNG in foreign markets. The financial viability of
the project will also be dependent upon a number of other factors, including the expected cost to construct the liquefaction facility, the terms and conditions
of the financing for the construction of the liquefaction facility, the cost of the natural gas supply, the costs to transport natural gas to the liquefaction
facility, the costs to operate the liquefaction facility and the costs to transport LNG from the liquefaction facility to customers in foreign markets
(particularly Europe and Asia). Some of these costs fluctuate
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based on a variety of factors, including supply and demand factors affecting the price of natural gas in the United States, supply and demand factors
affecting the costs for construction services for large infrastructure projects in the United States, and general economic conditions, there can be no
assurance that the parties will determine to proceed to develop this project.
The construction of the liquefaction project remains subject to further approvals and some approvals may be subject to further conditions, review and/or
revocation.
In December 2015, the FERC authorized Lake Charles LNG Export to site, construct and operate the liquefaction project subject to various condition,
including a condition requiring all phases of the liquefaction project to be completed and in-service within five years of the date of the FERC authorization
order. The order also requires the modifications to our Trunkline pipeline facilities that connect to our Lake Charles facility and additionally requires
execution of a transportation contract for natural gas supply to the liquefaction facility prior to the initiation of construction of the liquefaction facility. In
December 2019, the FERC granted an extension of time until and including December 16, 2025, to complete construction of the liquefaction project and
pipeline facilities modifications and place the facilities into service. In May 2022, the FERC granted a second extension of time until and including
December 16, 2028 to complete construction of the liquefaction facilities modifications and place the facilities into service.
The export of LNG produced by any liquefaction facility in the United States requires export authorization from the DOE. The NGA requires the DOE to
approve applications for LNG exports unless such approval would be “inconsistent with the public interest.” In March 2013, Lake Charles LNG Export
obtained a DOE authorization to export LNG to countries with which the United States has or will have Free Trade Agreements (“FTA”) for trade in
natural gas (the “FTA Authorization”). In July 2016, Lake Charles LNG Export also obtained a conditional DOE authorization to export LNG to countries
that do not have an FTA for trade in natural gas (the “Non-FTA Authorization”) subject to commencement of exports no later than December 2020. Lake
Charles LNG Export applied for an extension of the deadline to commerce exports under the Non-FTA Authorization to December 2025 and the DOE
approved such extension request in October 2020. Lake Charles LNG Export applied for a second extension of the deadline to commence exports and in
April 2023 the DOE denied this request in connection with a new DOE policy related to extension requests.
In light of this new policy, in August 2023, Lake Charles LNG Export applied for a new Non-FTA Authorization which, if approved, would provide for a
new deadline to commence exports to Non-FTA countries, which deadline would be seven years from the date of such approval. In January 2024, the Biden
administration announced a moratorium on the approval of LNG export authorizations by the DOE and instructed the DOE to conduct studies related to the
cumulative impact of LNG exports on domestic natural gas prices, climate change and other matters. The Biden administration stated that these studies
were necessary to enable the DOE to make determinations related to the statutory “public interest” standard. The DOE has stated that these studies will take
several months to complete, after which a draft policy statement will be made available for public comment prior to finalizing the policy statement. This
process is not expected to be completed prior to the U.S. Presidential election in November 2024.
Based on this action by the Biden administration, there is uncertainty as to the ultimate determinations by the DOE with respect to whether the export of
LNG from a specific liquefaction facility, such as the proposed Lake Charles LNG facility, will be considered “not inconsistent with the public interest,”
the applicable standard for approval under the NGA. Accordingly, there can be no assurance as to whether Lake Charles LNG Export will receive approval
of its application for a Non-FTA Authorization.
Integration of assets acquired in past acquisitions or future acquisitions with our existing business will be a complex and time-consuming process. A failure
to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial
condition, results of operations or cash available for distribution to Unitholders.
The difficulties of integrating past and future acquisitions with our business include, among other things:
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operating a larger combined organization in new geographic areas and new lines of business;
hiring, training or retaining qualified personnel to manage and operate our growing business and assets;
integrating management teams and employees into existing operations and establishing effective communication and information exchange with such
management teams and employees;
diversion of management’s attention from our existing business;
assimilation of acquired assets and operations, including additional regulatory programs;
loss of customers or key employees;
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• maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and
corporate governance matters; and
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integrating new technology systems for financial reporting.
If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from past acquisitions and future acquisitions
resulting in a negative impact to our future results of operations. In addition, acquired assets may perform at levels below the forecasts used to evaluate
their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could
be negatively impacted.
Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of
each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or
potential problems and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may
not be performed on every asset, and environmental problems, may not be observable even when an inspection is undertaken.
We are affected by competition from other midstream, transportation, terminalling and storage companies.
We experience competition in all of our business segments. With respect to our midstream operations, we compete for both natural gas supplies and
customers for our services. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress,
treat, process, transport, store and market natural gas.
Our natural gas and NGL transportation pipelines and storage facilities compete with other interstate and intrastate pipeline companies and storage
providers in the transportation and storage of natural gas and NGLs. The principal elements of competition among pipelines are rates, terms of service,
access to sources of supply and the flexibility and reliability of service. Natural gas and NGLs also compete with other forms of energy, including
electricity, coal, fuel oils and renewable or alternative energy. Competition among fuels and energy supplies is primarily based on price; however, non-price
factors, including governmental regulation, environmental impacts, efficiency, ease of use and handling, and the availability of subsidies and tax benefits
also affects competitive outcomes.
In markets served by our NGL pipelines, we compete with other pipeline companies and barge, rail and truck fleet operations. We also face competition
with other storage and fractionation facilities based on fees charged and the ability to receive, distribute and/or fractionate the customer’s products.
Our crude oil and refined petroleum products pipelines face significant competition from other pipelines for large volume shipments. These operations also
face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude and refined product terminals compete with
terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with
marketing and trading operations.
We, Sunoco LP and USAC may not be able to fully execute our growth strategy if we encounter increased competition for qualified assets.
Our strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage and other energy
infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance
our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into
discussions regarding the acquisition of additional assets and businesses, stand-alone development projects or other transactions that we believe will
present opportunities to realize synergies and increase our cash flow.
Consistent with our strategy, we may, from time to time, engage in discussions with potential sellers regarding the possible acquisition of additional assets
or businesses. Such acquisition efforts may involve our participation in processes that involve a number of potential buyers, commonly referred to as
“auction” processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with
the potential seller. We cannot give assurance that our acquisition efforts will be successful or that any acquisition will be completed on terms considered
favorable to us.
In addition, we may experience increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of
assets could result in us losing to other bidders more often or acquiring assets at higher prices, both of which would limit our ability to fully execute our
growth strategy. Inability to execute our growth strategy may materially adversely impact our results of operations.
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We compete with other businesses in our market with respect to attracting and retaining qualified employees.
Our continued success depends on our ability to attract and retain qualified personnel in all areas of our business. We compete with other businesses in our
market with respect to attracting and retaining qualified employees. A tight labor market, increased overtime and a higher full-time employee ratio may
cause labor costs to increase. A shortage of qualified employees may require us to enhance wage and benefits packages in order to compete effectively in
the hiring and retention of such employees or to hire more expensive temporary employees. No assurance can be given that our labor costs will not
increase, or that such increases can be recovered through increased prices charged to customers. We are especially vulnerable to labor shortages in oil and
gas drilling areas when energy prices drive higher exploration and production activity.
Regulatory Matters
Increased regulation of hydraulic fracturing or produced water disposal could result in reductions or delays in crude oil and natural gas production in our
areas of operation, which could adversely impact our business and results of operations.
The hydraulic fracturing process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that
chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies and may have other detrimental impacts on public health,
safety, welfare and the environment. In addition, the water disposal process has come under scrutiny from sections of the public as well as environmental
and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. Additionally, several candidates for
political office in both state and federal government have announced intentions to impose greater restrictions on hydraulic fracturing or produced water
disposal. For example, on January 27, 2021, the Biden Administration issued an executive order temporarily suspending the issuance of new authorizations,
and suspending the issuance of new leases pending completion of a review of current practices, for oil and gas development on federal lands and waters
(but not tribal lands that the federal government merely holds in trust). The suspension of these federal leasing activities prompted legal action by several
states against the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021,
followed by a permanent injunction in August 2022, effectively halting implementation of the leasing suspension. Relatedly, the Department of the Interior
(“DOI”) released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an
overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with
known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. In 2022,
the recommendations in this report resulted in a reduction in the volume of onshore land held for lease and an increased royalty rate, and in 2023, the DOI
proposed a rule to modernize the fiscal terms of the leasing program. Implementation of many of the recommendations in the DOI report will require
Congressional action and we cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal
oil and gas activities have the potential to result in increased costs on us and our customers, decrease demand for our services on federal lands, and
adversely impact our business. Separately, in November 2022, the BLM proposed a rule that would limit flaring from well sites on federal lands, as well as
allow the delay or denial of permits if the BLM finds that an operator’s methane waste minimization plan is insufficient. In addition, the Colorado Energy
and Carbon Management Commission (formerly the Colorado Oil and Gas Conservation Commission) adopted new rules to cover a variety of matters
related to public health, safety, welfare, wildlife, and environmental resources, and is considering draft rules regarding the cumulative impacts of oil and
gas projects; most significantly, these rule changes establish more stringent setbacks (2,000-foot, instead of the prior 500-foot) on new oil and gas
development and eliminate routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions. Some
local communities have adopted, or are considering adopting, additional restrictions for oil and gas activities, such as requiring even greater setbacks.
While the final impacts of these developments cannot be predicted, the adoption of new laws or regulations imposing additional permitting, disclosures,
restrictions or costs related to hydraulic fracturing or produced water disposal or prohibiting hydraulic fracturing in proximity to areas considered to be
environmentally sensitive could make drilling certain wells impossible or less economically attractive. As a result, the volume of crude oil and natural gas
we gather, transport and store for our customers could be substantially reduced which could have an adverse effect on our financial condition or results of
operations.
Legal or regulatory actions related to the Dakota Access Pipeline could cause an interruption to current or future operations, which could have an adverse
effect on our business and results of operations.
On July 27, 2016, the Standing Rock Sioux Tribe and other Native American tribes (the “Tribes”) filed a lawsuit in the United States District Court for the
District of Columbia (“District Court”) challenging permits issued by the USACE permitting Dakota Access to cross the Missouri River at Lake Oahe in
North Dakota. The case was subsequently amended to challenge an easement issued by the USACE allowing the pipeline to cross land owned by the
USACE adjacent to the Missouri River. As a result of this litigation, the District Court vacated the easement, ordered USACE to prepare an Environmental
Impact Statement (“EIS”), and order the pipeline shutdown and drained of oil. Dakota Access and USACE appealed this decision and moved for a
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stay of the District Court’s orders. On August 5, 2020, the Court of Appeals granted a stay of the portion of the District Court order that required Dakota
Access to shut the pipeline down and empty it of oil, but the Court of Appeals denied a stay of the easement vacatur. The August 5, 2020 order also stated
that the Court of Appeals expected the USACE to clarify its position with respect to whether USACE intends to allow the continued operation of the
pipeline notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary. Following this order, the Tribes
filed a motion with the District Court seeking an injunction to prevent the continued operation of the pipeline. On January 26, 2021, the Court of Appeals
affirmed the District Court’s order requiring an EIS and its order vacating the easement. In the same January 26 order, the Court of Appeals also overturned
the District Court’s July 6, 2020 order that the pipeline be shut down and emptied of oil because of the lack of findings sufficient to satisfy the legal
requirements for injunctive relief, including a finding of irreparable harm to the Tribes in the absence of an injunction. Dakota Access filed for rehearing en
banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota Access filed a petition with the U.S. Supreme Court to hear
the case. Oppositions were filed by the Solicitor General and plaintiffs, and Dakota Access has filed its reply.
The District Court scheduled a status conference for February 10, 2021 to discuss the impact of the Court of Appeals’ ruling on the pending motion for
injunctive relief, as well as USACE’s expectations as to how it will proceed in light of the Court of Appeals’ recent vacatur ruling. USACE filed a motion
for a continuance of the status conference until April 9, 2021, and this motion was approved by the District Court on February 9, 2021. Dakota Access and
the Tribes filed their supplemental declarations on April 19, 2021 and April 26, 2021, respectively. On April 26, 2021, the District Court requested that
USACE advise it by May 3, 2021 as to USACE’s current position, if it has one, with respect to the motion. On May 3, 2021, USACE advised the District
Court that it had not changed its position with respect to its opposition to the Tribes’ motion for injunction. The USACE also advised the District Court that
it expected that the EIS will be completed by March 2022. On May 21, 2021 the District Court denied the plaintiffs’ request for an injunction. The District
Court further directed the parties to file a joint status report by June 11, 2021 concerning potential next steps in the litigation. On June 22, 2021, the District
Court terminated the consolidated lawsuits and dismissed all remaining outstanding counts without prejudice. On January 20, 2022, the Standing Rock
Sioux Tribe withdrew as a cooperating agency on the draft EIS, prompting the USACE to temporarily pause on the draft EIS. On September 8, 2023, the
USACE published the Draft EIS. Comments to the Draft EIS were due on December 13, 2023. The USACE anticipates that a Final EIS and Record of
Decision would be issued in 2024. For further information, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements
and Supplementary Data” in this annual report.
Our interstate natural gas pipelines are subject to laws, regulations and policies governing the rates they are allowed to charge for their services, which
may prevent us from fully recovering our costs.
Laws, regulations and policies governing interstate natural gas pipeline rates could affect the ability of our interstate pipelines to establish rates, to charge
rates that would cover future increases in its costs, or to continue to collect rates that cover current costs.
We are required to file with the FERC tariff rates (also known as recourse rates) that shippers may pay for interstate natural gas transportation services. We
may also agree to discount these rates on a not unduly discriminatory basis or negotiate rates with shippers who elect not to pay the recourse rates. The
FERC must approve or accept all rate filings for us to be allowed to charge such rates.
The FERC may review existing tariff rates on its own initiative or upon receipt of a complaint filed by a third party. The FERC may, on a prospective basis,
order refunds of amounts collected if it finds the rates to have been shown not to be just and reasonable or to have been unduly discriminatory. The FERC
has recently exercised this authority with respect to several other pipeline companies. If the FERC were to initiate a proceeding against us and find that our
rates were not just and reasonable or were unduly discriminatory, the maximum rates we are permitted to charge may be reduced and the reduction could
have an adverse effect on our revenues and results of operations.
The costs of our interstate pipeline operations may increase, and we may not be able to recover all of those costs due to FERC regulation of our rates. If we
propose to change our tariff rates, our proposed rates may be challenged by the FERC or third parties, and the FERC may deny, modify or limit our
proposed changes if we are unable to persuade the FERC that changes would result in just and reasonable rates that are not unduly discriminatory. We also
may be limited by the terms of rate case settlement agreements or negotiated rate agreements with individual customers from seeking future rate increases,
or we may be constrained by competitive factors from charging our tariff rates.
To the extent our costs increase in an amount greater than our revenues increase, or there is a lag between our cost increases and our ability to file for and
obtain rate increases, our operating results would be negatively affected. Even if a rate increase is permitted by the FERC to become effective, the rate
increase may not be adequate. We cannot guarantee that our interstate pipelines will be able to recover all of our costs through existing or future rates.
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The ability of interstate pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes as a cost-of-service element in their
regulated rates has been subject to extensive litigation before the FERC and the courts for a number of years. Effective January 2018, the 2017 Tax Cuts
and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the maximum corporate tax rate. On March 15,
2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated entity rates. The FERC issued a Revised
Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit master limited partnerships to recover an
income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to a remand from the United States Court of
Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the FERC had not justified its conclusion that a
pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy by both including an income-tax allowance
in its cost of service and earning a return on equity (“ROE”) calculated using the discounted cash flow methodology. On July 18, 2018, the FERC clarified
that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and providing evidentiary support that it
is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’
income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an opinion upholding FERC’s decision
denying a separate master limited partnership recovery of an income tax allowance and its decision not to require the master limited partnership to refund
accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding individual entities’ ability to argue in support of recovery
of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance to a master limited partnership, the impacts
that FERC’s policy on the treatment of income taxes may have on the rates an interstate pipeline held in a tax-pass-through entity can charge for the FERC
regulated transportation services are unknown at this time.
Even without application of FERC’s recent rate making-related policy statements and rulemakings, under the NGA, FERC or our shippers may challenge
the cost-of-service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related
components, but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost of service rate. Moreover, we
receive revenues from our pipelines based on a variety of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-
based rates. Many of our interstate pipelines, such as Tiger, Midcontinent Express and Fayetteville Express, have negotiated market rates that were agreed
to by customers in connection with long-term contracts entered into to support the construction of the pipelines. Other systems, such as FGT, Transwestern
and Panhandle, have a mix of tariff rate, discount rate, and negotiated rate agreements. The revenues we receive from natural gas transportation services we
provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate
federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed
review of all of a pipeline’s cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.
By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the NGA to determine
whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate
proceeding under Section 4 of the NGA. The NGA Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1, 2019.
The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the initial
decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on the initial
decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United States Court
of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently appealed these
orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and stayed the consolidated
appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September 25, 2023, the FERC issued
its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle has timely filed its Petition for
Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited request for rehearing of the
September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by operation of law on November 27, 2023.
On November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which has been protested by several parties. On
January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified certain discussion from its September 25,
2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the January 5, 2024
order.
On July 1, 2022, Transwestern filed a rate case pursuant to Section 4 of the NGA. By order dated September 9, 2022, a procedural schedule was adopted in
this proceeding, setting the commencement of the hearing for June 22, 2023 with an initial decision anticipated by November 15, 2023. By a subsequent
order dated February 14, 2023, the procedural schedule was suspended based on representations that the participants have reached an agreement in
principle to resolve all issues in this
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proceeding and a settlement is being prepared for filing at FERC. A settlement was filed with the FERC on April 5, 2023, and approved by order dated
June 30, 2023.
On December 1, 2022, Sea Robin filed a general rate proceeding under Section 4 of the NGA reflecting a general rate increase for gathering and
transportation services. A hearing in the proceeding is scheduled for October 24, 2023 with an initial decision anticipated by March 19, 2024. The parties
have reached a settlement in the case, and the settlement was filed with the FERC on December 29, 2023.
Our interstate natural gas pipelines are subject to laws, regulations and policies governing terms and conditions of service, which could adversely affect
our business and results of operations.
In addition to rate oversight, the FERC’s regulatory authority extends to many other aspects of the business and operations of our interstate natural gas
pipelines, including:
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terms and conditions of service;
the types of services interstate pipelines may or must offer their customers;
siting and construction of new facilities;
acquisition, extension or abandonment of services or facilities;
reporting and information posting requirements;
accounts and records; and
relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.
Compliance with these requirements can be costly and burdensome. In addition, we cannot guarantee that the FERC will authorize tariff changes and other
activities we might propose and to undertake in a timely manner and free from potentially burdensome conditions. Future changes to laws, regulations,
policies and interpretations thereof may impair our access to capital markets or may impair the ability of our interstate pipelines to compete for business,
may impair their ability to recover costs or may increase the cost and burden of operation.
The FERC issued a Notice of Inquiry (“NOI”) on April 19, 2018 (“2018 NOI”) initiating a review of its policies on certification of natural gas pipelines,
including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities (“1999 Policy
Statement”), issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued
another NOI (“2021 NOI”), reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021. In September
2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized under Sections
3 and 7 of the NGA. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to the FERC on
January 7, 2022. On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certificate of New Interstate
Natural Gas Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022
Policy Statements”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy
statements, and requested further comments. The FERC stated that it will not apply the now draft 2022 Policy Statements to pending applications or
applications to be filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Policy Statements were due on April 25, 2022,
and reply comments were due on May 25, 2022. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements
that might affect our natural gas pipeline or LNG facility projects, or when such new policies, if any, might become effective. We do not expect that any
change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United
States.
Rate regulation or market conditions may not allow us to recover the full amount of increases in the costs of our crude oil, NGL and refined products
pipeline operations.
Transportation provided on our common carrier interstate crude oil, NGL and refined products pipelines is subject to rate regulation by the FERC, which
requires that tariff rates for transportation on these oil pipelines be just and reasonable and not unduly discriminatory. If we propose new or changed rates,
the FERC or interested persons may challenge those rates and the FERC is authorized to suspend the effectiveness of such rates for up to seven months and
to investigate such rates. If, upon completion of an investigation, the FERC finds that the proposed rate is unjust or unreasonable, it is authorized to require
the carrier to refund revenues in excess of the prior tariff during the term of the investigation. The FERC also may investigate, upon complaint or on its
own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon
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an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.
The primary ratemaking methodology used by the FERC to authorize increases in the tariff rates of petroleum pipelines is price indexing. The FERC’s
ratemaking methodologies may limit our ability to set rates based on our costs or may delay the use of rates that reflect increased costs. On March 25,
2020, the FERC issued a Notice of Inquiry seeking comment on a proposal to change the preliminary screen for complaints against oil pipeline index rate
increases to a “Percentage Comparison Test” consistent with the preliminary screen used by the FERC for protests against oil pipeline index rate increases.
The FERC also requested comment on whether the appropriate threshold for the screen is a 10% or more differential between a proposed index rate
increase and the annual percentage change in cost of service reported by the pipeline. Initial comments were due June 16, 2020, and reply comments were
due July 16, 2020.
On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish
guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases. Specifically, the policy statement adopted the
proposal in the FERC’s earlier Notice of Inquiry issued on March 25, 2020 to eliminate the “Substantially Exacerbate Test” as the preliminary screen
applied to complaints against index rate increases and instead adopt the proposal to apply the “Percentage Comparison Test” as the preliminary screen for
both protests and complaints against index rate increases. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for
complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index
rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash
flows.
On June 18, 2020, FERC issued a NOI requesting comments on a proposed oil pipeline index for the five-year period commencing July 1, 2021 and ending
June 30, 2026, and requested comments on whether and how the index should reflect the Revised Policy Statement and FERC’s treatment of accumulated
deferred income taxes as well as FERC’s revised ROE methodology.
On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December
17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and
ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus
0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period
July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to
reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20
order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain
pending at the D.C. Circuit.
Under the Energy Policy Act of 1992 (the “Energy Policy Act”), certain interstate pipeline rates were deemed just and reasonable or “grandfathered.”
Revenues are derived from such grandfathered rates on most of our FERC-regulated pipelines. A person challenging a grandfathered rate must, as a
threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of
the service that formed the basis for the rate. If the FERC were to find a substantial change in circumstances, then the existing rates could be subject to
detailed review and there is a risk that some rates could be found to be in excess of levels justified by the pipeline’s costs. In such event, the FERC could
order us to reduce pipeline rates prospectively and to pay refunds to shippers.
If the FERC’s petroleum pipeline ratemaking methodologies procedures changes, the new methodology or procedures could adversely affect our business
and results of operations.
State regulatory measures could adversely affect the business and operations of our midstream and intrastate pipeline and storage assets.
Our midstream and intrastate transportation and storage operations are generally exempt from FERC regulation under the NGA, but FERC regulation still
significantly affects our business and the market for our products. The rates, terms and conditions of service for the interstate services we provide in our
intrastate gas pipelines and gas storage are subject to FERC regulation under Section 311 of the NGPA. Our pipeline systems of Enable Oklahoma
Intrastate Transmission, LLC, Oasis Pipeline, LP, Houston Pipe Line Company LP, ETC Katy Pipeline, LLC, Energy Transfer Fuel, LP, Lobo Pipeline
Company, LLC, Pelico Pipeline, LLC, Regency Intrastate Gas LP, Red Bluff Express Pipeline, LLC, Trans-Pecos Pipeline, LLC and Comanche Trail
Pipeline, LLC provide such services. Under Section 311, rates charged for transportation and storage must be fair and equitable. Amounts collected in
excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s statement of
operating conditions, are subject to FERC review and approval. Should the FERC determine not to authorize rates equal to or greater than our costs of
service, our cash flow would be negatively affected.
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Our midstream and intrastate gas and oil transportation pipelines and our intrastate gas storage operations are subject to state regulation. All of the states in
which we operate midstream assets, intrastate pipelines or intrastate storage facilities have adopted some form of complaint-based regulation, which allow
producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to the fairness of rates and terms of access. The
states in which we operate have ratable take statutes, which generally require gathering pipelines to take, without undue discrimination, production that
may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as
to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to
purchase or transport natural gas. Should a complaint be filed in any of these states or should regulation become more active, our business may be
adversely affected.
Our intrastate transportation operations located in Texas are also subject to regulation as gas utilities by the TRRC. Texas gas utilities must publish the rates
they charge for transportation and storage services in tariffs filed with the TRRC, although such rates are deemed just and reasonable under Texas law
unless challenged in a complaint.
We are subject to other forms of state regulation, including requirements to obtain operating permits, reporting requirements, and safety rules (see
description of federal and state pipeline safety regulation below). Violations of state laws, regulations, orders and permit conditions can result in the
modification, cancellation or suspension of a permit, civil penalties and other relief.
Certain of our assets may become subject to regulation.
The distinction between federally unregulated gathering facilities and FERC-regulated transmission pipelines under the NGA has been the subject of
extensive litigation and may be determined by the FERC on a case-by-case basis, although the FERC has made no determinations as to the status of our
facilities. Consequently, the classification and regulation of our gathering facilities could change based on future determinations by the FERC, the courts or
Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the
services we currently provide, and may include the potential for a termination of our gathering agreements with our customers.
Intrastate transportation of NGLs is largely regulated by the state in which such transportation takes place. Energy Transfer GC NGL’s pipeline transports
NGLs within the state of Texas and is subject to regulation by the TRRC. This NGLs transportation system offers services pursuant to an intrastate
transportation tariff on file with the TRRC. In 2013, Energy Transfer GC NGL’s pipeline also commenced the interstate transportation of NGLs, which is
subject to the FERC’s jurisdiction under the Interstate Commerce Act (“ICA”) and the Energy Policy Act. Both intrastate and interstate NGL transportation
services must be provided in a manner that is just, reasonable, and non-discriminatory. The tariff rates established for interstate services were based on a
negotiated agreement; however, if the FERC’s ratemaking methodologies were imposed, they may, among other things, delay the use of rates that reflect
increased costs and subject us to potentially burdensome and expensive operational, reporting and other requirements. In addition, the rates, terms and
conditions for shipments of crude oil, petroleum products and NGLs on our pipelines are subject to regulation by the FERC if the NGLs are transported in
interstate or foreign commerce, whether by our pipelines or other means of transportation. Since we do not control the entire transportation path of all crude
oil, petroleum products and NGLs on our pipelines, FERC regulation could be triggered by our customers’ transportation decisions.
In addition, if any of our pipelines were found to have provided services or otherwise operated in violation of the NGA, NGPA, or ICA, this could result in
the imposition of administrative and criminal remedies and civil penalties, as well as a requirement to disgorge charges collected for such services in excess
of the rate established by the FERC. Any of the foregoing could adversely affect revenues and cash flow related to these assets.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.
Pursuant to authority under the NGPSA and HLPSA, PHMSA has established a series of rules requiring pipeline operators to develop and implement
integrity management programs for natural gas transmission and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect high
consequence areas (“HCAs”) which are areas where a release could have the most significant adverse consequences, including high population areas,
certain drinking water sources, and unusually sensitive ecological areas. These regulations require operators of covered pipelines to:
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perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.
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In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. At this time, we cannot
predict the ultimate cost of compliance with applicable pipeline integrity management regulations, as the cost will vary significantly depending on the
number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. We will continue our pipeline integrity testing programs
to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating
expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Any changes to pipeline safety
laws by Congress and regulations by PHMSA that result in more stringent or costly safety standards could have a significant adverse effect on us and
similarly situated midstream operators. For example, in October 2019, PHMSA published the first of three regulations relating to new or more stringent
requirements for certain natural gas lines and gathering lines, that had originally been proposed in 2016 as part of PHMSA’s “Gas Megarule.” The
rulemaking imposed numerous requirements on onshore gas transmission pipelines relating to MAOP, reconfirmation and exceedance reporting, the
integrity assessment of additional pipeline mileage found in MCAs, non-HCAs, Class 3 and Class 4 areas by 2023, and the consideration of seismicity as a
risk factor in integrity management. PHMSA’s second final rule, applicable to hazardous liquid transmission and gathering pipelines, significantly extended
and expanded the reach of certain integrity management requirements, use of in-line inspection tools by 2039 (unless the pipeline cannot be modified to
permit such use), increased annual, accident, and safety-related conditional reporting requirements, and expanded use of leak detection systems beyond
HCAs. The third final rule was published in August 2022, which adjusted the repair criteria for pipelines in HCAs, created new criteria for pipelines in
non-HCAs, and strengthened integrity management assessment requirements, among other items. The changes adopted by these rulemakings could have a
material adverse effect on our results of operations and costs of transportation services.
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in
more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.
The NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”). Among
other things, the 2011 Pipeline Safety Act increased the penalties for safety violations and directed the Secretary of Transportation to promulgate rules or
standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system
installation, testing to confirm that the material strength of certain pipelines are above 30% of specified minimum yield strength, and operator verification
of records confirming the MAOP of certain interstate natural gas transmission pipelines. In March 2022, PHMSA issued a final rule increasing the
maximum administrative fines for safety violations were increased to account for inflation, with maximum civil penalties set at $239,142 per day, with a
maximum of $2,391,412 for a series of violations. Upon reauthorization of PHMSA, Congress often directs the agency to complete certain rulemakings.
For example, in the Consolidated Appropriations Bill for Fiscal Year 2021, Congress reauthorized PHMSA through fiscal year 2023 and directed the
agency to move forward with several regulatory actions, including the “Pipeline Safety: Class Location Change Requirements” and the “Pipeline Safety:
Safety of Gas Transmission and Gathering Pipelines” proposed rulemaking, To that end, PHMSA issued the three final rules discussed above, significantly
expanding reporting and safety requirements of operators of gas gathering pipelines, imposing safety regulations on approximately 400,000 miles of
previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend
reporting requirements to all gas gathering operators, and apply a set of minimum safety requirements to certain gas gathering pipelines with large
diameters and high operating pressures. Additionally, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators
of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas from
related pipeline facilities. The safety enhancement requirements and other provisions of Congressional mandates to PHMSA, as well as any implementation
of PHMSA rules thereunder or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install
new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks
could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial
condition.
Our business involves the generation, handling and disposal of hazardous substances, hydrocarbons and wastes which activities are subject to
environmental and worker health and safety laws and regulations that may cause us to incur significant costs and liabilities.
Our business is subject to stringent federal, tribal, state, and local laws and regulations governing the discharge of materials into the environment, worker
health and safety and protection of the environment. These laws and regulations may require the acquisition of permits for the construction and operation of
our pipelines, plants and facilities, result in capital expenditures to manage, limit or prevent emissions, discharges or releases of various materials from our
pipelines, plants and facilities, impose specific health and safety standards addressing worker protection, and impose substantial liabilities for pollution
resulting from our construction and operations activities. Several governmental authorities, such as the EPA and analogous state agencies have the power to
enforce compliance with these laws and regulations and the permits issued under them and frequently mandate
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difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations and permits may result in the assessment of
significant administrative, civil and criminal penalties, the imposition of investigatory remedial and corrective action obligations, suspension and
debarment from federal contracting opportunities, the occurrence of delays in permitting and completion of projects, and the issuance of injunctive relief.
For example, following a state grand jury investigation and the filing of charges alleging criminal misconduct involving the construction and related
activities of the Mariner East 2 pipeline (“Mariner 2”), in August 2022 we entered into a plea of no contest with the Pennsylvania Attorney General’s
Office that requires us to pay fines to the Commonwealth, pay for independent evaluations of potential water quality impacts to residential water supplies
and compensate any affected homeowners, and to also pay $10 million to support water quality improvement projects. Any additional requirements from
the PADEP regarding Mariner 2 or other of our pipeline projects may result in delays in the completion of these projects. Subsequently, the EPA issued a
Notice of Proposed Debarment (“NPD”) on October 28, 2022, arising from SPLP’s and ETC Northeast Pipeline, LLC’s nolo contendere plea agreements
and convictions for violations of Pennsylvania’s Clean Streams Law related to the Revolution and Mariner 2 pipelines. The following entities were
proposed for debarment: (1) SPLP (pleading entity); (2) ETC Northeast Pipeline, LLC (pleading entity); (3) Energy Transfer LP; (4) SemGroup LLC; and
(5) LE GP, LLC. The NPD presently prevents the named entities from pursuing or renewing Federal government contracts or Federal financial assistance
agreements. While we are engaging with the EPA to attempt to resolve the matter, at this time there can be no assurance that the EPA will not finalize a
debarment applicable to the named entities for a set period of time, or expand the debarment to other Energy Transfer affiliates. Currently, none of the
entities named in the NPD are party to any Federal government contracts or Federal financial assistance agreements.
Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances,
hydrocarbons or wastes have been disposed or released, even under circumstances where the substances, hydrocarbons or wastes have been released by a
predecessor operator. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property and
natural resource damage allegedly caused by noise, odor or the release of hazardous substances, hydrocarbons or wastes into the environment.
We may incur substantial environmental costs and liabilities because of the underlying risk arising out of our operations. Although we have established
financial reserves for our estimated environmental remediation liabilities, additional contamination or conditions may be discovered, resulting in increased
remediation costs, liabilities or natural resource damages that could substantially increase our costs for site remediation projects. Accordingly, we cannot
assure you that our current reserves are adequate to cover all future liabilities, even for currently known contamination.
Uncertainty about the future course of regulation continues to exist following the change in U.S. presidential administrations in January 2021. Upon taking
office, the Biden Administration issued an executive order directing all federal agencies to review and take action to address any federal regulations
promulgated during the prior administration that may be inconsistent with the current administration’s policies. As a result, several regulatory
developments have occurred, but it remains unclear the degree to which this will continue . The executive order also established a Working Group that is
called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of
methane.” During 2021, the Working Group published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public
comment on these estimates. The Working Group’s interim estimate of the social cost of carbon has been subject to litigation in 2022, but is in use while
litigation is pending. The EPA has also separately developed its own proposal for a social cost of carbon, which is significantly higher than that proposed
by the Working Group. The EPA’s proposal is currently undergoing independent peer review and is not yet in use by the agency. Further regulation of air
emissions, as well as uncertainty regarding the future course of regulation, could eventually reduce the demand for oil and natural gas and, in turn, have a
material adverse effect on our business, financial condition or results of operations.
Changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, emission
standards, or storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. For
example, in October 2015, the EPA published a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for
ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards, and the EPA finalized its attainment/non-attainment
designations in 2018, though these are subject to change. In December 2020, the EPA announced that it was retaining without revision the 2015 NAAQS
for ozone. However, the Biden Administration has announced plans to formally review this decision and consider instituting a more stringent standard.
Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modified sources of air pollution in
newly designated non-attainment areas. Also, states are expected to implement more stringent requirements as a result of this new final rule, which could
apply to our customers’ operations. Compliance with this final rule or any other new regulations could, among other things, require installation of new
emission controls on some of our equipment, result in longer permitting timelines or new restrictions or prohibitions with respect to permits or projects, and
significantly increase our capital expenditures and operating costs, which could adversely impact our business. Historically, we have been able to satisfy the
more stringent nitrogen oxide emission reduction requirements that
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affect our compressor units in ozone non-attainment areas at reasonable cost, but there is no assurance that we will not incur material costs in the future to
meet the new, more stringent ozone standard.
Regulations under the Clean Water Act, Oil Pollution Act of 1990, as amended (“OPA”), and state laws impose regulatory burdens on terminal operations.
Spill prevention control and countermeasure requirements of federal and state laws require containment to mitigate or prevent contamination of waters in
the event of a refined product overflow, rupture, or leak from above-ground pipelines and storage tanks. The Clean Water Act also requires us to maintain
spill prevention control and countermeasure plans at our terminal facilities with above-ground storage tanks and pipelines. In addition, OPA requires that
most fuel transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. Facilities that are adjacent to
water require the engagement of Federally Certified Oil Spill Response Organizations to be available to respond to a spill on water from above-ground
storage tanks or pipelines.
Transportation and storage of refined products over and adjacent to water involves risk and potentially subjects us to strict, joint, and potentially unlimited
liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone
of the United States.
In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. The Clean Water Act imposes restrictions and strict
controls regarding the discharge of pollutants into navigable waters, with the potential of substantial liability for the violation of permits or permitting
requirements.
Terminal operations and associated facilities are subject to the Clean Air Act as well as comparable state and local statutes. Under these laws, permits may
be required before construction can commence on a new source of potentially significant air emissions, and operating permits may be required for sources
that are already constructed. If regulations become more stringent, additional emission control technologies.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the services we
provide.
Climate change continues to attract considerable public, governmental and scientific attention. As a result, numerous proposals have been made and are
likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts
have included consideration of cap-and-trade programs, carbon taxes and GHG reporting and tracking programs, and regulations that directly limit GHG
emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level to date.
However, Canada has implemented a federal carbon pricing regime, and, in the United States, President Biden has announced that he intends to pursue
substantial reductions in GHG emissions, particularly from the oil and gas sector. For example, on January 27, 2021, President Biden signed an executive
order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal
government, the elimination of subsidies provided to the fossil fuel industry, an increase in the production of offshore wind energy, and an increased
emphasis on climate-related risks across government agencies and economic sectors. In August 2022, the IRA 2022 was signed into law, which
appropriates significant federal funding for renewable energy initiatives and amends the federal Clean Air Act to impose a first-time fee on the emission of
methane from sources required to report their GHG emissions to the EPA. The IRA 2022 imposes a methane emissions charge on sources required to report
their GHG emissions to the EPA, which started in calendar year 2024 at $900 per ton of methane, increases to $1,200 in 2025, and will be set at $1,500 for
2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022.Additionally, the EPA has adopted rules under
authority of the Clean Air Act that, among other things, establish Potential for Significant Deterioration (“PSD”) construction and Title V operating permit
reviews for GHG emissions from certain large stationary sources that are also potential major sources of certain principal, or criteria, pollutant emissions,
which reviews could require securing PSD permits at covered facilities emitting GHGs and meeting “best available control technology” standards for those
GHG emissions. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and
natural gas system sources in the United States, including, among others, onshore processing, transmission, storage and distribution facilities. In October
2015, the EPA amended and expanded the GHG reporting requirements to all segments of the oil and natural gas industry, including gathering and boosting
facilities and blowdowns of natural gas transmission
Federal agencies also have begun directly regulating GHG emissions, such as methane, from oil and natural gas operations. In June 2016, the EPA
published New Source Performance Standards (“NSPS”), known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil
and natural gas sector to reduce these methane gas and VOC emissions. These Subpart OOOOa standards expand previously issued NSPS published by the
EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic
controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. In
September 2020, the EPA finalized amendments to Subpart OOOOa that rescind the methane limits for new,
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reconstructed and modified oil and natural gas production sources while leaving in place the general emission limits for VOCs. In addition, the rulemaking
removes from the oil and natural gas category the natural gas transmission and storage segment. However, Congress passed, and President Biden signed
into law, a revocation of the 2020 rulemaking, effectively reinstating the 2016 standards. Additionally, in December 2023, the EPA issued a final rule that
established OOOOb new source and OOOOc first-time existing source standards of performance for GHG and VOC emissions for crude oil and natural gas
well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities, Owners or
operators of affected emission units or processes will have to comply with specific standards of performance that may include leak detection using optical
gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements,
operations and maintenance requirements, and so-called “green well” completion requirements. The December 2023 rule also revises requirements for
fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response
program to timely mitigate emissions events, triggering certain response and repair requirements, and provides additional options for the use of advanced
monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. Fines and penalties for violations of these
rules can be substantial. Several states have also adopted, or are considering, adopting, regulations related to GHG emissions, some of which are more
stringent than those implemented by the federal government. Methane emission standards imposed on the oil and gas sector could result in increased costs
to our operations or those of our customers as well as result in delays or curtailment in such operations, which costs, delays or curtailment could adversely
affect our business.
At the international level, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United
Nations Framework Convention on Climate Change in Paris, France in signing the “Paris Agreement,” a treaty that requires member countries to submit
individually-determined, non-binding GHG emission reduction goals every five years beginning in 2020. Although the United States withdrew from the
Agreement under the Trump administration, President Biden recommitted the United States in February 2021, and, in April 2021, announced a new, more
rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The
international community gathered again in Glasgow in November 2021 at COP26 during which multiple announcements were made, including a call for
parties to eliminate fossil fuel subsidies, amongst other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch
of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by
2030, including “all feasible reductions” in the energy sector. At the 27th Conference of the Parties in Sharm El-Sheik in November 2022, countries
reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase-out of fossil fuel subsidies. The United States also
announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane
emissions to help create a market for low methane-intensity natural gas. In December 2023, at COP28, parties signed onto an agreement to transition away
from fossil fuels in energy systems and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set.
Although no timeline to phase out or phase down all fossil fuels has been made, there can be no guarantees that countries will not seek to implement a
timeline in the future.
President Biden’s January 2021 climate change executive order also directed the Secretary of the Interior to pause new oil and natural gas leasing on public
lands or in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust
royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate action, to account for
corresponding climate costs. This pause was subsequently subject to a permanent injunction in August 2022, effectively halting implementation of the
leasing suspension with respect to those leases canceled or postponed prior to March 24, 2021. The executive order also directed the federal government to
identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil
fuels. As noted above, a separate executive order issued in January 2021 established a Working Group that is called on to, among other things, develop
methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane.” During 2021, the Working Group
published interim estimates of the social costs of carbon, methane, and nitrous oxide and sought public comment on these estimates. The Working Group’s
interim estimate of the social cost of carbon, $51 per ton, has been subject to litigation in 2022, but is in use while litigation is pending. It is difficult to
predict how these measures may impact our business; however, any new restrictions on oil and gas permitting or leasing on federal lands could discourage
new oil and gas development by our customers, which could have an adverse effect on our business.
The adoption, strengthening and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise
restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our
business, financial condition, demand for our services, results of operations, and cash flows. Litigation risks are also increasing, as several oil and gas
companies have been sued for allegedly causing climate-related damages due to their production and sale of fossil fuel products or for allegedly being
aware of the impacts of climate change for some time but failing to adequately disclose such risks to their investors or customers.
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There are also increasing financing risks for fossil fuel energy companies, as various investors become increasingly concerned about the potential effects of
climate change and may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing for fossil
fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources such as wind and solar
photovoltaic, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy companies. For
example, at COP26, the GFANZ announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital
committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their
financing, investing, and/or underwriting activities to net zero by 2050. Additionally, there is the possibility that financial institutions will be required to
adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve announced that it has joined NGFS, a consortium of
financial regulators focused on addressing climate-related risks in the financial sector. In November 2021, the Federal Reserve issued a statement in support
of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory
authorities. In September 2022, the Federal Reserve announced that six of the United States’ largest banks will participate in a pilot climate scenario
analysis exercise, which launched in early 2023, to enhance the ability of firms and supervisors to measure and manage climate-related financial risk.
While we cannot predict what polices may result from these developments, such efforts could make it more difficult for exploration and production
companies and midstream companies, like us, to secure funding as well as negatively affect the cost of, and terms for, financings to fund growth projects or
other aspects of our business. Additionally, in March 2022 the SEC released a proposed rule requiring climate disclosures, which is expected to be finalized
in 2024. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure
requirements.
Climatic events in the areas in which we operate, whether from climate change or otherwise, can cause disruptions, and in some cases, delays in, or
suspension of, our services. These event, including but not limited to drought, winter storms, wildfire, extreme temperatures or flooding, may become more
intense or more frequent as a result of climate change and could have an adverse effect on our continued operations. If such effects were to occur, our
operations could be adversely affected in various ways, including damages to our facilities or our customers’ facilities from powerful winds or rising
waters. We may experience increased insurance costs, or difficulty obtaining adequate insurance coverage, for our assets in areas subject to more frequent
severe weather. We may not be able to recoup these increased costs through the rates we charge our customers. Extreme weather events could cause
damage to property or facilities that could exceed our insurance coverage and our business, financial condition and results of operations could be adversely
affected.
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our NGLs and natural gas is generally
improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we
transport, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that
climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict
how the market for our products could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would
be expected to have an adverse effect on our business.
A climate-related decrease in demand for crude oil, natural gas and other hydrocarbon products could negatively affect our business.
Supply and demand for crude oil, natural gas and other hydrocarbon products we handle is dependent upon a variety of factors, many of which are beyond
our control. These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation
measures and climate change regulations, technological advances in fuel economy and energy generation devices. For example, legislative, regulatory or
executive actions intended to reduce emissions of GHGs could increase the cost of consuming crude oil, natural gas and other hydrocarbon products,
thereby potentially causing a reduction in the demand for such products. A broader transition to alternative fuels or energy sources, whether resulting from
potential new government regulation, carbon taxes, governmental incentives and funding such as those provided in the IRA 2022, or consumer preferences
could result in decreased demand for hydrocarbon products like crude oil, natural gas and NGLs that we handle. Any decrease in demand for these products
could consequently reduce demand for our services and could have a negative effect on our business.
Increased attention to ESG matters and conservation measures may adversely impact our business.
Increasing attention to, and societal expectations on companies to address, climate change and other environmental and social impacts, investor and societal
expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for
fossil fuels and consequently demand for our midstream services, reduced profits, increased risk of investigations and litigation, and negative impacts on
the value of our assets and access to capital. Increasing attention to climate change and environmental conservation, for example, may result in reduced
demand for
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oil and natural gas products and additional governmental investigations and private litigation against us or our customers. To the extent that societal
pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to
climate change or asserted damage to the environment, or to other mitigating factors. While we may participate in various voluntary frameworks and
certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the
intended results on our ESG profile. Moreover, while we are pursuing various low-carbon opportunities such as renewable power generation, renewable
fuels, and carbon capture and storage projects through our alternative energy initiatives to address potential energy transition related risks, we cannot
guarantee that we will be able to execute these projects in a timely manner because of permitting, technology, or other risks or that such opportunities will
ultimately be successful.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary
disclosures will be based on expectations and assumptions. Such expectations and assumptions are necessarily uncertain and may be prone to error or
subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on
many ESG matters. Additionally, while we may also announce various voluntary ESG targets in the future, such targets are aspirational. We may not be
able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or
technical difficulties associated with achieving such results. To the extent that we do meet such targets, we may consider the acquisition of various credits
or offsets that may be deemed to assist in the achievement of such targets or otherwise mitigate our ESG impact instead of actual achievements of such
targets or actual changes in our ESG performance. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups
to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential
costs or technical or operational obstacles.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for
evaluating companies on their approach to ESG matters. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies
with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other
industries, which could have a negative impact on our access to and costs of capital. Additionally, to the extent ESG matters negatively impact our
reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
The swaps regulatory provisions of the Dodd-Frank Act and the rules adopted thereunder could have an adverse effect on our ability to use derivative
instruments to mitigate the risks of changes in commodity prices and interest rates and other risks associated with our business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires that certain classes of swaps be cleared on a
derivatives clearing organization and traded on a designated contract markets or other regulated exchange, unless exempt from such clearing and trading
requirements, which could result in the application of certain margin requirements imposed by derivatives clearing organizations and their members. The
CFTC and prudential regulators have also adopted mandatory margin requirements for uncleared swaps entered into between swap dealers and certain other
counterparties. We currently qualify for and rely upon an end-user exception from such clearing and margin requirements for the swaps we enter into to
hedge our commercial risks. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin
requirements to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally
comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge
our market risks with non-U.S. counterparties and may make transactions involving cross-border swaps more expensive and burdensome. Additionally, the
lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more difficult to satisfy our regulatory obligations.
Additional deepwater drilling laws and regulations, delays in the processing and approval of drilling permits and exploration, development, oil spill-
response and decommissioning plans, and other related developments may have a material adverse effect on our business, financial condition, or results of
operations.
The Federal Bureau of Ocean Energy Management (“BOEM”) and the federal Bureau of Safety and Environmental Enforcement (“BSEE”), each agencies
of the DOI, have imposed more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal
waters. Compliance with these more stringent regulatory requirements and with existing environmental and oil spill regulations, together with any
uncertainties or inconsistencies in
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decisions and rulings by governmental agencies, delays in the processing and approval of drilling permits or exploration, development, oil spill-response
and decommissioning plans, and possible additional regulatory initiatives could result in difficult and more costly actions and adversely affect or delay new
drilling and ongoing development efforts. For instance, in January 2021, the Biden Administration issued an executive order focused on climate change
that, among other things, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands or in offshore waters pending
completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas
resources extracted from public lands and offshore waters, or take other appropriate action, to account for corresponding climate costs.
In addition, new regulatory initiatives may be adopted or enforced by the BOEM or the BSEE in the future that could result in additional costs, delays,
restrictions, or obligations with respect to oil and natural gas exploration and production operations conducted offshore by certain of our customers.
Separately, in April 2023, BOEM and BSEE published a final rule regarding financial assurance requirements for offshore leases, particularly regarding
requirements for bonds above base amounts prescribed by regulation. In June 2023, BOEM issued a notice of proposed rulemaking seeking to modify its
criteria for determining bonds and financial assurance for offshore oil and gas lessees and other operators, which generally imposes more stringent
requirements for waiving supplemental bonding requirements and changes how BOEM calculates the amount of supplemental financial assurance required,
amongst other matters. At this time, we cannot determine with any certainty the amount of any additional financial assurance that may be ordered by
BOEM and required of us in the future, or that such additional financial assurance amounts can be obtained. The final publication or implementation of this
rule, as well as any new rules, regulations, or legal initiatives, could delay or disrupt our customers’ operations, increase the risk of expired leases due to
the time required to develop new technology, result in increased supplemental bonding and costs, limit activities in certain areas, or cause our customers’ to
incur penalties, or shut-in production or lease cancellation. Also, if material spill events were to occur in the future, the United States or other countries
could elect to issue directives to temporarily cease drilling activities offshore and, in any event, may from time to time issue further safety and
environmental laws and regulations regarding offshore oil and gas exploration and development. The overall costs imposed on our customers to implement
and complete any such spill response activities or any decommissioning obligations could exceed estimated accruals, insurance limits, or supplemental
bonding amounts, which could result in the incurrence of additional costs to complete. Separately, in January 2021, the Biden Administration issued orders
temporarily suspending the issuance of new authorizations and suspending the issuance of new leases pending completion of a review of current practices,
for oil and gas development on federal lands and waters. The suspension of these federal leasing activities prompted legal action by several states against
the Biden Administration, resulting in issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021 and permanent
injunction in August 2022, effectively halting implementation of the leasing suspension. Additionally, provisions in the IRA 2022 require that particular
offshore oil and gas lease sales under the 2017 – 2022 leasing program proceed, and the DOI has reinstated or announced plans for those sales. In
September 2023, the DOI published a proposed final offshore leasing program for 2024 – 2029, which was then approved by the Secretary of the Interior
and authorized three Gulf of Mexico leasing sales. Relatedly, the DOI released its report on federal gas leasing and permitting practices in November 2021,
referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty
and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat,
conservation, and historical and cultural resources. Implementation of many of the recommendations in the DOI report will require Congressional action
and we cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities
have the potential to result in increased costs on us and our customers, decrease demand for our services on federal lands, and adversely impact our
business and adversely impact our business. For example, in 2023, the DOI proposed a rule to modernize the fiscal terms of the leasing program, increase
costs associated with such leases and add new criteria for the DOI to consider when deciding whether to lease nominated lands. The Biden Administration
also published an order calling for an increase in the production of offshore wind energy, which may impact the use of federal waters. We cannot predict
with any certainty the full impact of any new laws or regulations on our customers’ drilling operations or on the cost or availability of insurance to cover
some or all of the risks associated with such operations. The occurrence of any one or more of these developments could result in decreased demand for our
services, which could have a material adverse effect on our business as well as our financial position, results of operation and liquidity.
Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the petroleum products that we
store and transport.
The petroleum products that we store and transport are sold by our customers for consumption into the public market. Various federal, state and local
agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality
specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In
addition, different product specifications for different markets impact the fungibility of products transported and stored in our pipeline systems and terminal
facilities and could require the
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construction of additional storage to segregate products with different specifications. We may be unable to recover these costs through increased revenues.
In addition, our patented butane blending services are reliant upon gasoline vapor pressure specifications. Significant changes in such specifications could
reduce butane blending opportunities, which would affect our ability to market our butane blending service licenses and which would ultimately affect our
ability to recover the costs incurred to acquire and integrate our butane blending assets.
Risks Relating to Our Partnership Structure
Issuance of Common Units or Other Classes of Equity
We may issue an unlimited number of limited partner interests or other classes of equity without the consent of our Unitholders, which will dilute
Unitholders’ ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit
distribution level.
Our Partnership Agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the Common Units,
without the approval of our Unitholders. The issuance of additional Common Units or other equity securities by us will have the following effects:
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our Unitholders’ current proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each Common Unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding Common Unit and/or Preferred Unit may be diminished; and
the market price of our Common Units and/or Preferred Units may decline.
Cash Distributions to Unitholders and Governance
Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.
The amount of cash we can distribute to our Unitholders depends upon the amount of cash we generate from our operations and from our subsidiaries,
Sunoco LP and USAC. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend upon, among other
things:
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•
•
•
•
the amount of natural gas, NGLs, crude oil and refined products transported in our pipelines;
the level of throughput in our processing and treating operations;
the fees we charge and the margins we realize for our services;
the price of natural gas, NGLs, crude oil and refined products;
the relationship between natural gas, NGL and crude oil prices;
the weather in our operating areas;
the level of competition from other midstream, transportation and storage and other energy providers;
the level of our operating costs;
prevailing economic conditions; and
the level and results of our derivative activities.
In addition, the actual amount of cash we and our subsidiaries, including Sunoco LP and USAC, will have available for distribution will also depend on
other factors, such as:
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the level of capital expenditures we and our subsidiaries make;
the level of costs related to litigation and regulatory compliance matters;
the cost of acquisitions, if any;
the levels of any margin calls that result from changes in commodity prices;
our and our subsidiaries’ debt service requirements;
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fluctuations in our and our subsidiaries’ working capital needs;
our and our subsidiaries’ ability to borrow under our revolving credit facility;
our and our subsidiaries’ ability to access capital markets;
restrictions on distributions contained in our and our subsidiaries’ debt agreements; and
the amount of cash reserves established by our general partner in its discretion for the proper conduct of our business.
Because of all these factors, we cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or
above our current quarterly distribution. The actual amount of cash that is available for distribution to our Unitholders will depend on numerous factors,
many of which are beyond our control or the control of our general partner.
Furthermore, our Unitholders should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and is not
solely a function of profitability, which is affected by non-cash items. As a result, we may declare and/or pay cash distributions during periods when we
record net losses.
Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to
Unitholders.
Our Partnership Agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to
fund our future operating expenditures. In addition, our Partnership Agreement permits our general partner to reduce available cash by establishing cash
reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future
distributions to partners. These cash reserves will affect the amount of cash available for distribution to Unitholders.
Unitholders may have liability to repay distributions.
Under certain circumstances, Unitholders may have to repay us amounts wrongfully distributed to them. Under Delaware law, we may not make a
distribution to Unitholders if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their
partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides
that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law, will be liable to
the limited partnership for the distribution amount for three years from the distribution date.
The NYSE does not require a publicly traded partnership like us to comply with certain corporate governance requirements.
Our common units, Series E Preferred Units and Series I Preferred Units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE
does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a
nominating and corporate governance committee. Accordingly, our Unitholders do not have the same protections afforded to stockholders of corporations
that are subject to all of the corporate governance requirements of the applicable stock exchange.
Our General Partner
The control of our general partner may be transferred to a third party without Unitholder consent.
Our general partner may transfer its general partner interest to a third party without the consent of the Unitholders. Any new owner of the general partner
would be in a position to replace the officers and directors of the general partner with its own designees and thereby exert significant influence over the
decisions made by such officers and directors.
The majority owner of our general partner has rights that protect him against dilution.
Through his controlling interest in our general partner, Kelcy Warren owns all of the outstanding Energy Transfer Class A Units, which represents an
approximately 20% voting interest in the Partnership. Under the terms of the Energy Transfer Class A Units, upon the issuance by the Partnership of
additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership will issue to the
general partner additional Energy Transfer Class A Units such that Mr. Warren maintains a voting interest in the Partnership that is equivalent to his voting
interest in the Partnership with respect to such Energy Transfer Class A Units (approximately 20%) prior to such issuance of common units. As a result,
Mr. Warren is partially protected against the dilutive effect of additional common unit issuances by the Partnership with respect to voting. As of
December 31, 2023, the Partnership had outstanding 833,486,004 Energy Transfer Class A Units.
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Cost reimbursements due to our general partner may be substantial and may reduce our ability to pay the distributions to Unitholders.
Prior to making any distributions to our Unitholders, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our
general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by the general partner. The
reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the Unitholders. Our general
partner has sole discretion to determine the amount of these expenses and fees.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and,
therefore, limited ability to influence management’s decisions regarding our business. Our Unitholders have no right to elect our general partner or the
board of directors of our general partner. Our general partner has the right to appoint and replace the members of the board, including all of its independent
directors. Mr. Warren owns an 81.2% membership interest in our general partner and controls our general partner and therefore has the ability to direct our
general partner with respect to the exercise of these governance rights.
If our Unitholders are dissatisfied with the general partner’s performance, they have limited ability to remove the general partner. The vote of the holders of
at least 66 2/3% of all outstanding common units is required to remove the general partner; however, Mr. Warren owns a significant number of common
units and, through his controlling interest in the general partner, owns all of the outstanding Energy Transfer Class A Units, which vote together with the
common units and entitle the holders of the Energy Transfer Class A Units to maintain the voting percentage in Energy Transfer represented by such
Energy Transfer Class A Units as of the date the initial Energy Transfer Class A Units were issued (approximately 20%) any time new common units are
issued. As of February 9, 2024, Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the
Partnership of 27%. As a result of this and other limitations, it may be more difficult to remove the general partner.
Furthermore, our Partnership Agreement contains provisions limiting the ability of common unitholders to call meetings or to obtain information about our
operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management. Common unitholders’
voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person or group that owns 20% or more
of such class of units then outstanding, other than, with respect to our common units, the general partner, its affiliates, their direct transferees and their
indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such common units
with the prior approval of the general partner, cannot vote on any matter.
Kelcy Warren owns a majority interest in, and controls, our general partner, and our general partner has sole responsibility for conducting our business
and managing our operations. The general partner may have conflicts of interest with us and limited fiduciary duties, and it may favor its own interests to
the detriment of us and our Unitholders.
Mr. Warren owns an 81.2% membership interest in, and therefore controls, the general partner and accordingly has the right to appoint and replace all of the
officers and directors of the general partner. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our
Unitholders, the directors and officers of the general partner also have a fiduciary duty to manage the general partner in a manner that is beneficial to its
majority owner, Mr. Warren. Conflicts of interest will arise between the general partner and its owner, on the one hand, and us and our Unitholders, on the
other hand. In resolving these conflicts of interest, the general partner may favor its own interests and the interests of its owner over our interests and the
interests of our Unitholders.
Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of
limited partners to remove our general partner or to take other action under the Partnership Agreement constituted participation in the “control” of our
business. Additionally, under Delaware law, our general partner has unlimited liability for the obligations of Energy Transfer, such as our debts and
environmental liabilities, except for those contractual obligations of Energy Transfer that are expressly made without recourse to the general partner.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of
the states in which we do business. Unitholders could have unlimited liability for obligations of the Partnership if a court or government agency determined
that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) a Unitholder’s right to act with
other Unitholders to remove or
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replace our general partner, to approve some amendments to our Partnership Agreement or to take other actions under the Partnership Agreement
constituted “control” of our business.
Our general partner has a limited call right that may require Unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 90% of our outstanding units, our general partner will have the right, but not the
obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less
than their then-current market price. As a result, Unitholders may be required to sell their units at an undesirable time or price and may not receive any
return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2023, the directors and executive
officers of our general partner owned approximately 10% of our Common Units.
Our Subsidiaries
We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.
We are a holding company, and our subsidiaries conduct all of our operations and own all of our operating assets. We do not have significant assets other
than the partnership interests and the equity in our subsidiaries. As a result, our ability to pay distributions to our Unitholders and to service our debt
depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be
restricted by, among other things, credit facilities and applicable state partnership laws and other laws and regulations. In particular, our Five-Year Credit
Facility, limits our and certain of our subsidiaries’ ability to make distributions. If we are unable to obtain funds from our subsidiaries, we may not be able
to pay distributions to our Unitholders or to pay interest or principal on our debt when due.
The interruption of distributions to us from our operating subsidiaries and equity investees may affect our ability to satisfy our obligations and to make
distributions to our partners.
We are a holding company with no business operations other than that of our operating subsidiaries. Our only significant assets are the equity interests we
own in our operating subsidiaries and equity investees. As a result, we depend upon the earnings and cash flow of our operating subsidiaries and equity
investees and any interruption of distributions to us may affect our ability to meet our obligations, including any obligations under our debt agreements, and
to make distributions to our partners.
Our subsidiaries are not prohibited from competing with us.
Neither our Partnership Agreement nor the partnership agreements of our subsidiaries, including Sunoco LP and USAC, prohibit our subsidiaries from
owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our subsidiaries may acquire, construct or dispose of any
assets in the future without any obligation to offer us the opportunity to purchase or construct any of those assets.
Sunoco LP and USAC may issue additional common units, which may increase the risk that each Partnership will not have sufficient available cash to
maintain or increase its per unit distribution level.
The partnership agreements of Sunoco LP and USAC allow each partnership to issue an unlimited number of additional limited partner interests. The
issuance of additional common units or other equity securities by each respective partnership will have the following effects:
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unitholders’ current proportionate ownership interest in each partnership will decrease;
the amount of cash available for distribution on each common unit or partnership security may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of each partnership’s common units may decline.
The payment of distributions on any additional units issued by Sunoco LP and USAC may increase the risk that either partnership may not have sufficient
cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations
A reduction in Sunoco LP’s distributions will disproportionately affect the amount of cash distributions to which Energy Transfer is entitled.
Energy Transfer indirectly owns all of the IDRs of Sunoco LP. These IDRs entitle the holder to receive increasing percentages of total cash distributions
made by Sunoco LP as such entity reaches established target cash distribution levels as specified in its
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partnership agreement. Energy Transfer currently receives its pro rata share of cash distributions from Sunoco LP based on the highest sharing level of 50%
in respect of the Sunoco LP IDRs.
A decrease in the amount of distributions by Sunoco LP to less than $0.65625 per unit per quarter would reduce Energy Transfer’s percentage of the
incremental cash distributions from Sunoco LP above $0.546875 per unit per quarter from 50% to 25%. As a result, any such reduction in quarterly cash
distributions from Sunoco LP would have the effect of disproportionately reducing the amount of all distributions that Energy Transfer receives, based on
its ownership interest in the IDRs as compared to cash distributions received from its Sunoco LP common units.
A significant decrease in demand for motor fuel, including increased consumer preference for alternative motor fuels, improvements in fuel efficiency or a
material shift toward electric or other alternative-power vehicles, in the areas Sunoco LP serves would reduce their ability to make distributions to its
unitholders.
For the year ended December 31, 2023, sales of refined motor fuels accounted for approximately 98% of Sunoco LP’s total revenues and 69% of gross
profit. A significant decrease in demand for motor fuel in the areas Sunoco LP serves could significantly reduce revenues and Sunoco LP’s ability to make
distributions to its unitholders, including Energy Transfer. Sunoco LP revenues are dependent on various trends, such as trends in commercial truck traffic,
travel and tourism in their areas of operation, and these trends can change. Regulatory action, including government imposed fuel efficiency standards, may
also affect demand for motor fuel. Because certain of Sunoco LP’s operating costs and expenses are fixed and do not vary with the volumes of motor fuel
distributed, their costs and expenses might not decrease ratably or at all should they experience such a reduction. As a result, Sunoco LP may experience
declines in their profit margin if fuel distribution volumes decrease.
Any technological advancements, regulatory changes or changes in consumer preferences causing a significant shift toward alternative motor fuels could
reduce demand for the conventional petroleum based motor fuels Sunoco LP currently sells. Additionally, a shift toward electric, hydrogen, natural gas or
other alternative-power vehicles could fundamentally change customers’ shopping habits or lead to new forms of fueling destinations or new competitive
pressures.
New technologies have been developed and governmental mandates have been implemented to improve fuel efficiency, which may result in decreased
demand for petroleum-based fuel. For example, in December 2021, the Biden Administration announced revised GHG emissions standards for light-duty
vehicle fleets for Model Years 2023-2026, which some manufacturers may meet by increasing fuel efficiency or increasing the prevalence of zero-
emissions vehicles in their fleets. The Biden Administration has also set a goal for federal vehicle acquisitions to be 100% zero-emissions vehicles by 2035,
which may further influence the composition of vehicle fleets. Laws such as the Bipartisan Infrastructure Act and the IRA 2022 allocate funds to the
development of electric vehicle infrastructure and provide incentives for consumers and manufacturers related to their use or development of electric
vehicles, and the adoption rate of electric vehicles in the U.S. has continued to accelerate, with projections for the future rate of adoption in some reports
more than doubling in recent years. Any of these actions could result in fewer visits to convenience stores or independently operated commission agents
and dealer locations, a reduction in demand from their wholesale customers, decreases in both fuel and merchandise sales revenue, or reduced profit
margins, any of which could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for
distribution to its unitholders.
Sunoco LP’s financial condition and results of operations are influenced by changes in the prices of motor fuel, which may adversely impact margins,
customers’ financial condition and the availability of trade credit.
Sunoco LP’s operating results are influenced by prices for motor fuel. General economic and political conditions, acts of war or terrorism and instability in
oil producing regions, particularly in the Middle East and South America, could significantly impact crude oil supplies and petroleum costs. Significant
increases or high volatility in petroleum costs could impact consumer demand for motor fuel and convenience merchandise. Such volatility makes it
difficult to predict the impact that future petroleum costs fluctuations may have on Sunoco LP’s operating results and financial condition. Sunoco LP is
subject to dealer tank wagon pricing structures at certain locations further contributing to margin volatility. A significant change in any of these factors
could materially impact both wholesale and retail fuel margins, the volume of motor fuel distributed or sold at retail, and overall customer traffic, each of
which in turn could have a material adverse effect on Sunoco LP’s business, financial condition, results of operations and cash available for distribution to
its unitholders.
Significant increases in wholesale motor fuel prices could impact Sunoco LP as some of their customers may have insufficient credit to purchase motor fuel
from us at their historical volumes. Higher prices for motor fuel may also reduce access to trade credit support or cause it to become more expensive.
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The industries in which Sunoco LP operates are subject to seasonal trends, which may cause its operating costs to fluctuate, affecting its cash flow.
Sunoco LP relies in part on customer travel and spending patterns and may experience more demand for gasoline in the late spring and summer months
than during the fall and winter. Travel, recreation and construction are typically higher in these months in the geographic areas in which Sunoco LP or its
commission agents and dealers operate, increasing the demand for motor fuel that they sell and distribute. Therefore, Sunoco LP’s revenues and cash flows
are typically higher in the second and third quarters of our fiscal year. As a result, Sunoco LP’s results from operations may vary widely from period to
period, affecting Sunoco LP’s cash flow.
The dangers inherent in the storage and transportation of motor fuel could cause disruptions in Sunoco LP’s operations and could expose them to
potentially significant losses, costs or liabilities.
Sunoco LP stores motor fuel in underground and aboveground storage tanks. Sunoco LP transports the majority of its motor fuel in its own trucks, instead
of by third-party carriers. Sunoco LP’s operations are subject to significant hazards and risks inherent in transporting and storing motor fuel. These hazards
and risks include, but are not limited to, traffic accidents, fires, explosions, spills, discharges, and other releases, any of which could result in distribution
difficulties and disruptions, environmental pollution, governmentally-imposed fines or clean-up obligations, personal injury or wrongful death claims, and
other damage to its properties and the properties of others. Any such event not covered by Sunoco LP’s insurance could have a material adverse effect on
its business, financial condition, results of operations and cash available for distribution to its unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks which may adversely affect their financial condition, results of operations,
cash flows and ability to make distributions to its unitholders.
Sunoco LP’s fuel storage terminals are subject to operational and business risks, the most significant of which include the following:
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the inability to renew a ground lease for certain of their fuel storage terminals on similar terms or at all;
the dependence on third parties to supply their fuel storage terminals;
outages at their fuel storage terminals or interrupted operations due to weather-related or other natural causes;
the threat that the nation’s terminal infrastructure may be a future target of terrorist organizations;
the volatility in the prices of the products stored at their fuel storage terminals and the resulting fluctuations in demand for storage services;
the effects of a sustained recession or other adverse economic conditions;
the possibility of federal and/or state regulations that may discourage their customers from storing gasoline, diesel fuel, ethanol and jet fuel at their fuel
storage terminals or reduce the demand by consumers for petroleum products;
competition from other fuel storage terminals that are able to supply their customers with comparable storage capacity at lower prices; and
climate change legislation or regulations that restrict emissions of GHGs could result in increased operating and capital costs and reduced demand for
our storage services.
The occurrence of any of the above situations, amongst others, may affect operations at their fuel storage terminals and may adversely affect Sunoco LP’s
business, financial condition, results of operations, cash flows and ability to make distributions to its unitholders.
Negative events or developments associated with Sunoco LP’s branded suppliers could have an adverse impact on its revenues.
Sunoco LP believes that the success of its operations is dependent, in part, on the continuing favorable reputation, market value, and name recognition
associated with the motor fuel brands sold at Sunoco LP’s convenience stores and at stores operated by its independent, branded dealers and commission
agents. Erosion of the value of those brands could have an adverse impact on the volumes of motor fuel Sunoco LP distributes, which in turn could have a
material adverse effect on its business, financial condition, results of operations and ability to make distributions to its unitholders.
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Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise
inventory and its products and ingredients for its food service facilities. A disruption in supply or a change in either relationship could have a material
adverse effect on its business.
Sunoco LP currently depends on a limited number of principal suppliers in each of its operating areas for a substantial portion of its merchandise inventory
and its products and ingredients for its food service facilities. If any of Sunoco LP’s principal suppliers elect not to renew their contracts, Sunoco LP may
be unable to replace the volume of merchandise inventory and products and ingredients currently purchased from them on similar terms or at all in those
operating areas. Further, a disruption in supply or a significant change in Sunoco LP’s relationship with any of these suppliers could have a material
adverse effect on Sunoco LP’s business, financial condition and results of operations and cash available for distribution to its unitholders.
The wholesale motor fuel distribution industry and convenience store industry are characterized by intense competition and fragmentation and impacted by
new entrants. Failure to effectively compete could result in lower margins.
The market for distribution of wholesale motor fuel is highly competitive and fragmented, which results in narrow margins. Sunoco LP has numerous
competitors, some of which may have significantly greater resources and name recognition than it does. Sunoco LP relies on its ability to provide value-
added, reliable services and to control its operating costs in order to maintain our margins and competitive position. If Sunoco LP fails to maintain the
quality of its services, certain of its customers could choose alternative distribution sources and margins could decrease. While major integrated oil
companies have generally continued to divest retail sites and the corresponding wholesale distribution to such sites, such major oil companies could shift
from this strategy and decide to distribute their own products in direct competition with Sunoco LP, or large customers could attempt to buy directly from
the major oil companies. The occurrence of any of these events could have a material adverse effect on Sunoco LP’s business, financial condition, results of
operations and cash available for distribution to its unitholders.
The geographic areas in which Sunoco LP operates and supplies independently operated commission agent and dealer locations are highly competitive and
marked by ease of entry and constant change in the number and type of retailers offering products and services of the type we and our independently
operated commission agents and dealers sell in stores. Sunoco LP competes with other convenience store chains, independently owned convenience stores,
motor fuel stations, supermarkets, drugstores, discount stores, dollar stores, club stores, mass merchants and local restaurants. Over the past two decades,
several non-traditional retailers, such as supermarkets, hypermarkets, club stores and mass merchants, have impacted the convenience store industry,
particularly in the geographic areas in which Sunoco LP operates, by entering the motor fuel retail business. These non-traditional motor fuel retailers have
captured a significant share of the motor fuels market, and Sunoco LP expects their market share will continue to grow.
In some of Sunoco LP’s markets, its competitors have been in existence longer and have greater financial, marketing, and other resources than they or their
independently operated commission agents and dealers do. As a result, Sunoco LP’s competitors may be able to better respond to changes in the economy
and new opportunities within the industry. To remain competitive, Sunoco LP must constantly analyze consumer preferences and competitors’ offerings
and prices to ensure that they offer a selection of convenience products and services at competitive prices to meet consumer demand. Sunoco LP must also
maintain and upgrade our customer service levels, facilities and locations to remain competitive and attract customer traffic to our stores. Sunoco LP may
not be able to compete successfully against current and future competitors, and competitive pressures faced by Sunoco LP could have a material adverse
effect on its business, results of operations and cash available for distribution to its unitholders.
Sunoco LP may be subject to adverse publicity resulting from concerns over food quality, product safety, health or other negative events or developments
that could cause consumers to avoid its retail locations or independently operated commission agent or dealer locations.
Sunoco LP may be the subject of complaints or litigation arising from food-related illness or product safety which could have a negative impact on its
business. Negative publicity, regardless of whether the allegations are valid, concerning food quality, food safety or other health concerns, food service
facilities, employee relations or other matters related to its operations may materially adversely affect demand for its food and other products and could
result in a decrease in customer traffic to its retail stores or independently operated commission agent or dealer locations.
It is critical to Sunoco LP’s reputation that they maintain a consistent level of high quality at their food service facilities and other franchise or fast food
offerings. Health concerns, poor food quality or operating issues stemming from one store or a limited number of stores could materially and adversely
affect the operating results of some or all of their stores and harm the company-owned brands, continuing favorable reputation, market value and name
recognition.
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Sunoco LP does not own all of the land on which its retail service stations are located, and Sunoco LP leases certain facilities and equipment, and Sunoco
LP is subject to the possibility of increased costs to retain necessary land use which could disrupt its operations.
Sunoco LP does not own all of the land on which its retail service stations are located. Sunoco LP has rental agreements for approximately 33% of the
company, commission agent or dealer operated retail service stations where Sunoco LP currently controls the real estate. Sunoco LP also has rental
agreements for certain logistics facilities. As such, Sunoco LP is subject to the possibility of increased costs under rental agreements with landowners,
primarily through rental increases and renewals of expired agreements. Sunoco LP is also subject to the risk that such agreements may not be renewed.
Additionally, certain facilities and equipment (or parts thereof) used by Sunoco LP are leased from third parties for specific periods. Sunoco LP’s inability
to renew leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights,
could have a material adverse effect on its financial condition, results of operations and cash flows.
Sunoco LP is subject to federal laws related to the Renewable Fuel Standard.
New laws, new interpretations of existing laws, increased governmental enforcement of existing laws or other developments could require us to make
additional capital expenditures or incur additional liabilities. For example, certain independent refiners have initiated discussions with the EPA to change
the way the Renewable Fuel Standard (“RFS”) is administered in an attempt to shift the burden of compliance from refiners and importers to blenders and
distributors. Under the RFS, which requires an annually increasing amount of biofuels to be blended into the fuels used by U.S. drivers, refiners/importers
are obligated to obtain renewable identification numbers (“RINs”) either by blending biofuel into gasoline or through purchase in the open market. If the
obligation was shifted from the importer/refiner to the blender/distributor, the Partnership would potentially have to utilize the RINs it obtains through its
blending activities to satisfy a new obligation and would be unable to sell RINs to other obligated parties, which may cause an impact on the fuel margins
associated with Sunoco LP’s sale of gasoline. In addition, the RFS regulations are highly complex and evolving, and the RINs market is subject to
significant price volatility as a result. In December 2022, the EPA released a proposed rule under the RFS for renewable fuel volumes for the years 2023-
2025 that further increases targets for the production of renewable fuels. Subject to certain limitations, EPA now has significant discretion to set renewable
fuel targets under the RFS, which could result in increased compliance obligations on refiners and importers and transportation fuels. The price of RINs to
meet compliance obligations under the RFS could be substantial and adversely impact our financial condition.
The occurrence of any of the events described above could have a material adverse effect on Sunoco LP’s business, financial condition, results of
operations and cash available for distribution to its unitholders.
Sunoco LP is subject to federal, state and local laws and regulations that govern the product quality specifications of refined petroleum products it
purchases, stores, transports, and sells to its distribution customers.
Various federal, state, and local government agencies have the authority to prescribe specific product quality specifications for certain commodities,
including commodities that Sunoco LP distributes. Changes in product quality specifications, such as reduced sulfur content in refined petroleum products,
or other more stringent requirements for fuels, could reduce Sunoco LP’s ability to procure product, require it to incur additional handling costs and/or
require the expenditure of capital. If Sunoco LP is unable to procure product or recover these costs through increased selling price, it may not be able to
meet its financial obligations. Failure to comply with these regulations could result in substantial penalties for Sunoco LP.
If third-party pipelines and other facilities interconnected to Sunoco LP’s fuel storage terminals and transmix processing facilities become partially or fully
unavailable to transport refined products, Sunoco LP’s revenues could be adversely affected.
Sunoco LP depends upon third-party pipelines and other facilities that provide delivery options to and from its fuel storage terminals and transmix
processing facilities. Since Sunoco LP does not own or operate these pipelines or other facilities, their continuing operation in their current manner is not
within Sunoco LP’s control. If any of these third-party facilities become partially or fully unavailable, or if the quality specifications for their facilities
change so as to restrict our ability to utilize them, Sunoco LP’s financial condition and results of operations could be adversely affected.
The third parties on whom Sunoco LP relies for transportation services to its fuel storage terminals and transmix processing facilities are subject to
complex federal, state, and other laws that could adversely affect Sunoco LP’s financial condition and results of operations.
The operations of the third parties on whom Sunoco LP relies for transportation services are subject to complex and stringent laws and regulations that
require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third
parties may incur substantial costs in order to comply with existing
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laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations
become applicable to their operations, these changes may affect the costs that Sunoco LP pays for services. Similarly, a failure to comply with such laws
and regulations by the third parties could have a material adverse effect on Sunoco LP’s financial condition and results of operations.
Failure of Sunoco LP to complete its acquisition of NuStar and successfully integrate the businesses of Sunoco LP and NuStar in the expected time frame
could negatively impact the price of Sunoco LP’s common units and have a material adverse effect on its results of operations, cash flows and financial
position.
If Sunoco LP’s acquisition of NuStar is not completed for any reason, including as a result of failure to obtain all requisite regulatory approvals or Sunoco
LP’s unitholders failing to approve the applicable proposals, the anticipated benefits of the acquisition may not be realized or may take longer to realize
than expected. The success of the merger will depend, in part, on the ability of Sunoco LP to realize the anticipated benefits from combining its business
and NuStar. If Sunoco LP and NuStar are unable to successfully combine their businesses, the anticipated benefits of the merger may take longer to realize
than expected. In addition, the actual integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the
merger.
Additionally, Sunoco LP would be subject to a number of risks, including the following:
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negative reactions from the financial markets, including negative impacts on the price of Sunoco LP’s common units;
negative reactions from Sunoco LP’s customers, distributors, suppliers, vendors, landlords, joint venture partners and/or other business partners;
Sunoco LP will still be obligated to pay certain significant costs relating to its acquisition of NuStar, such as legal, accounting, financing, advisory
and/or printing fees;
Sunoco LP may be obligated to pay a termination fee as required by the merger agreement governing the acquisition;
the merger agreement governing the acquisition places certain restrictions on the conduct of Sunoco LP’s business, which may delay or prevent the
undertaking of business opportunities that, absent the merger agreement governing the acquisition, may have been pursued;
• matters relating to Sunoco LP’s acquisition of NuStar (including integration planning) require substantial commitments of time and resources by
Sunoco LP’s management, which may have resulted in the distraction from ongoing business operations and pursuing other opportunities that could
have been beneficial;
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litigation related to any failure of Sunoco LP to complete its acquisition of NuStar or related to any enforcement proceeding commenced against
Sunoco LP to perform its respective obligations under the merger agreement governing the acquisition; and
loss of key employees, the disruption of each of Sunoco LP’s and NuStar’s ongoing businesses and relationships with customers, or inconsistencies in
their standards, controls, procedures and policies.
If the acquisition is not completed, the risks described above may materialize and they may have a material adverse effect on Sunoco LP’s results of
operations, cash flows, financial position and/or price of its common units.
USAC’s customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of
compression units they currently own or using alternative technologies for enhancing crude oil production.
USAC’s customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their
operations by purchasing and operating their own compression fleets in lieu of using USAC’s compression services. The historical availability of attractive
financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units
more affordable to USAC’s customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and
USAC’s customers may elect to use these alternative technologies instead of the gas lift compression services USAC provides. Such vertical integration,
increases in vertical integration or use of alternative technologies could result in decreased demand for USAC’s compression services, which may have a
material adverse effect on its business, results of operations, financial condition and reduce its cash available for distribution.
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A significant portion of USAC’s services are provided to customers on a month-to-month basis, and USAC cannot be sure that such customers will continue
to utilize its services.
USAC’s contracts typically have initial terms between six months to five years, depending on the application and location of the compression unit. After
the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by USAC or USAC’s customers upon notice
as provided for in the applicable contract. For the year ended December 31, 2023, approximately 22% of USAC’s compression services on a revenue basis
were provided on a month-to-month basis to customers who continue to utilize its services following expiration of the primary term of their contracts.
These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If a significant number of these
customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could
have a material adverse effect on USAC’s business, results of operations, financial condition and cash available for distribution.
USAC’s preferred units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of its common units.
USAC’s preferred units rank senior to all of its other classes or series of equity securities with respect to distribution rights and rights upon liquidation.
These preferences could adversely affect the market price for its common units or could make it more difficult for USAC to sell its common units in the
future.
In addition, distributions on USAC’s preferred units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts
to a quarterly distribution of $24.375 per preferred unit. If USAC does not pay the required distributions on its preferred units, USAC will be unable to pay
distributions on its common units. Additionally, because distributions on USAC’s preferred units are cumulative, USAC will have to pay all unpaid
accumulated distributions on the preferred units before USAC can pay any distributions on its common units. Also, because distributions on USAC’s
common units are not cumulative, if USAC does not pay distributions on its common units with respect to any quarter, USAC’s common unitholders will
not be entitled to receive distributions covering any prior periods if USAC later recommences paying distributions on its common units.
USAC’s preferred units are convertible into common units by the holders of USAC’s preferred units or by USAC in certain circumstances. USAC’s
obligation to pay distributions on USAC’s preferred units, or on the common units issued following the conversion of USAC’s preferred units, could
impact USAC’s liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions and
other general Partnership purposes. USAC’s obligations to the holders of USAC’s preferred units could also limit its ability to obtain additional financing
or increase its borrowing costs, which could have an adverse effect on its financial condition.
Risks Related to Conflicts of Interest
The fiduciary duties of our general partner’s officers and directors may conflict with those of Sunoco LP’s or USAC’s respective general partners.
Conflicts of interest may arise because of the relationships among Sunoco LP, USAC, their general partners and us. Our General Partner’s directors and
officers have fiduciary duties to manage our business in a manner beneficial to us and our Unitholders. Some of our general partner’s directors or officers
are also directors and/or officers of Sunoco LP’s general partner or USAC’s general partner, and have fiduciary duties to manage the respective businesses
of Sunoco LP and USAC in a manner beneficial to Sunoco LP, USAC and their respective unitholders. The resolution of these conflicts may not always be
in our best interest or that of our Unitholders.
Although we control Sunoco LP and USAC through our ownership of Sunoco LP’s and USAC’s general partners, Sunoco LP’s and USAC’s general
partners owe duties to Sunoco LP and Sunoco LP’s unitholders and USAC and USAC’s unitholders, respectively, which may conflict with our interests.
Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and Sunoco LP and
USAC and their respective limited partners, on the other hand. The directors and officers of Sunoco LP’s and USAC’s general partners have duties to
manage Sunoco LP and USAC, respectively, in a manner beneficial to us. At the same time, the general partners have fiduciary duties to manage Sunoco
LP and USAC in a manner beneficial to Sunoco LP and USAC and their respective limited partners. The boards of directors of Sunoco LP’s and USAC’s
general partner will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts
may not always be in our best interest.
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For example, conflicts of interest with Sunoco LP and USAC may arise in the following situations:
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the allocation of shared overhead expenses to Sunoco LP, USAC and us;
the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Sunoco LP and USAC, on the other
hand;
the determination of the amount of cash to be distributed to Sunoco LP’s and USAC’s partners and the amount of cash to be reserved for the future
conduct of Sunoco LP’s and USAC’s businesses;
the determination whether to make borrowings under Sunoco LP’s and USAC’s revolving credit facilities to pay distributions to their respective
partners;
the determination of whether a business opportunity (such as a commercial development opportunity or an acquisition) that we may become aware of
independently of Sunoco LP and USAC is made available for Sunoco LP and USAC to pursue; and
any decision we make in the future to engage in business activities independent of Sunoco LP and USAC.
Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties
to us, which may permit them to favor their own interests to the detriment of us.
Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our
general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:
•
•
•
•
•
•
•
our general partner is allowed to take into account the interests of parties other than us, including Sunoco LP and USAC, and their respective affiliates
and any general partners and limited partnerships acquired in the future, in resolving conflicts of interest, which has the effect of limiting its fiduciary
duties to us.
our general partner has limited its liability and reduced its fiduciary duties under the terms of our Partnership Agreement, while also restricting the
remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units,
Unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable
state law.
our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and
reserves, each of which can affect the amount of cash that is available for distribution.
our general partner determines which costs it and its affiliates have incurred are reimbursable by us.
our Partnership Agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering
into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual
arrangements are fair and reasonable to us.
our general partner controls the enforcement of obligations owed to us by it and its affiliates.
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Our Partnership Agreement limits our general partner’s fiduciary duties to us and restricts the remedies available for actions taken by our general partner
that might otherwise constitute breaches of fiduciary duty.
Our Partnership Agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law.
For example, our Partnership Agreement:
•
•
•
permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles
our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of,
or factors affecting, us, our affiliates or any limited partner;
provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
generally provides that affiliated transactions and resolutions of conflicts of interest not approved by a conflicts committee of the board of directors of
our general partner and not involving a vote of Unitholders must be on terms no less favorable to us than those generally being provided to or available
from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our
general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly favorable
or advantageous to us;
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•
•
•
•
provides that unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty;
provides that our general partner may resolve any conflicts of interest involving us and our general partner and its affiliates, and any resolution of a
conflict of interest by our general partner that is “fair and reasonable” to us will be deemed approved by all partners, including the Unitholders, and
will not constitute a breach of the Partnership Agreement;
provides that our general partner may, but is not required, in connection with its resolution of a conflict of interest, to seek “special approval” of such
resolution by appointing a conflicts committee of the general partner’s board of directors composed of two or more independent directors to consider
such conflicts of interest and to recommend action to the board of directors, and any resolution of the conflict of interest by the conflicts committee
shall be conclusively deemed “fair and reasonable” to us; and
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any
acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general
partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
Our general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our
Unitholders.
Our Partnership Agreement requires our general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to
fund our future operating expenditures. In addition, our Partnership Agreement permits our general partner to reduce available cash by establishing cash
reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future
distributions to partners. These cash reserves will affect the amount of cash available for distribution to Unitholders.
Affiliates of our general partner may compete with us.
Except as provided in our Partnership Agreement, affiliates and related parties of our general partner are not prohibited from engaging in other businesses
or activities, including those that might be in direct competition with us.
Tax Risks to Unitholders
Our tax treatment depends on our continuing status as a partnership for federal income tax purposes, as well as our not being subject to a material amount
of entity-level taxation. If the IRS were to treat us and our subsidiaries, including Sunoco LP and USAC as a corporation for federal income tax purposes
or if we, Sunoco LP or USAC become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution
would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax
purposes. We have not requested, and do not plan to request, a ruling from the IRS on this matter. The value of our investments in Sunoco LP and USAC,
depend largely on Sunoco LP and USAC being treated as partnerships for federal income tax purposes. Despite the fact that we, Sunoco LP and USAC are
each a limited partnership under Delaware law, we would each be treated as a corporation for federal income tax purposes unless we satisfy a “qualifying
income” requirement. Based upon our current operations and current Treasury Regulations, we believe we, Sunoco LP and USAC satisfy the qualifying
income requirement. Failing to meet the qualifying income requirement or a change in current law could cause us, Sunoco LP or USAC to be treated as a
corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we, Sunoco LP or USAC were treated as a corporation for federal income tax purposes, we would pay federal income tax at the corporate tax rate and we
would likely pay additional state income taxes at varying rates. Distributions to Unitholders would generally be taxed again as corporate distributions, and
none of our income, gains, losses or deductions would flow through to Unitholders. Because a tax would be imposed upon us as a corporation, our cash
available for distribution to Unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in
the anticipated cash flow and after-tax return to the Unitholders, likely causing a substantial reduction in the value of our units.
At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise,
or other forms of taxation. We currently own property or conduct business in many states that impose a margin or franchise tax. In the future, we may
expand our operations. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could
substantially reduce our cash available for distribution to our Unitholders. Our Partnership Agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for U.S.
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federal, state, local or foreign income tax purposes, the target distribution amounts may be adjusted to reflect the impact of that law or interpretation on us.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes
or differing interpretations, possibly applied on a retroactive basis.
The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by
administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered
substantive changes to the existing United States federal income tax laws that affect publicly traded partnerships, including proposals that would eliminate
our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded
partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for
our partnership tax treatment. Further, while Unitholders of publicly traded partnerships are, subject to certain limitations, entitled to a deduction equal to
20% of their allocable share of a publicly traded partnership’s “qualified business income,” this deduction is scheduled to expire with respect to taxable
years beginning after December 31, 2025.
In addition, the U.S. Department of the Treasury has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded
partnerships. There can be no assurance that there will not be further changes to United States federal income tax laws or the U.S. Department of the
Treasury’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the United States federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more
difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for United States federal income tax
purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively
impact the value of an investment in our units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative
developments and proposals and their potential effect on your investment in our units.
If the IRS contests the federal income tax positions we take, the market for our units may be adversely affected and the costs of any such contest will reduce
cash available to pay our debt securities and for distributions to our Unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions
that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A
court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our units, and
the prices at which they trade. In addition, the costs of any contest between us and the IRS will result in a reduction in our cash available to pay our debt
securities and for distribution to our Unitholders and thus will be borne indirectly by our Unitholders.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and
interest) resulting from such audit adjustments directly from us, in which case our cash available to pay our debt securities and for distribution to our
Unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and
interest) resulting from such audit adjustment directly from us. To the extent possible, our general partner may elect to either pay the taxes (including any
applicable penalties and interest) directly to the IRS or, if we are eligible, issue an information statement to each Unitholder and former Unitholder with
respect to an audited and adjusted return. Although our general partner may elect to have our Unitholders and former Unitholders take such audit
adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year
under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current Unitholders
may bear some or all of the tax liability resulting from such audit adjustment, even if such Unitholders did not own units in us during the tax year under
audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to
our Unitholders might be substantially reduced.
Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Our Unitholders are required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether
or not they receive cash distributions from us. Our Unitholders may not receive cash distributions from us equal to their share of our taxable income or
even equal to the actual tax liability that results from that income.
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Tax gain or loss on disposition of our units could be more or less than expected.
If a Unitholder sells their units, the Unitholder will recognize a gain or loss equal to the difference between the amount realized and that Unitholder’s tax
basis in those units. Because distributions in excess of a Unitholder’s allocable share of our net taxable income decrease such Unitholder’s tax basis in their
units, the amount, if any, of such prior excess distributions with respect to the units a Unitholder sells will, in effect, become taxable income to a Unitholder
if such units are sold at a price greater than their tax basis in those units, even if the price such Unitholder receives is less than their original costs. In
addition, because the amount realized includes a Unitholder’s share of our nonrecourse liabilities, if a Unitholder sells their units, a Unitholder may incur a
tax liability in excess of the amount of cash received from the sale.
A substantial portion of the amount realized from a Unitholder’s sale of their units, whether or not representing gain, may be taxed as ordinary income to
such Unitholder due to potential recapture items, including depreciation recapture. Thus, a Unitholder may recognize both ordinary income and capital loss
from the sale of Common Units if the amount realized on a sale of such units is less than such Unitholder’s adjusted basis in the units. Net capital loss may
only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a Unitholder sells their
units, such Unitholder may recognize ordinary income from our allocations of income and gain to such Unitholder prior to the sale and from recapture
items that generally cannot be offset by any capital loss recognized upon the sale of units.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to
them. For example, virtually all of our income allocated to organizations that are exempt from United States federal income tax, including IRAs and other
retirement plans, will be unrelated business taxable income and will be taxable to them. Additionally, all or part of any gain recognized by such tax-exempt
organization upon a sale or other disposition of our units may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should
consult a tax advisor before investing in our units.
Non-United States Unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.
Non-United States Unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with
a United States trade or business (“effectively connected income”). Income allocated to our Unitholders and any gain from the sale of our units will
generally be considered to be “effectively connected” with a United States trade or business. As a result, distributions to a non-United States Unitholder
will be subject to withholding at the highest applicable effective tax rate and a non-United States Unitholder who sells or otherwise disposes of a unit will
also be subject to United States federal income tax on the gain realized from the sale or disposition of that unit. In addition to the withholding tax imposed
on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding tax on the amount of any
distribution in excess of our cumulative net income. We intend to treat all of our distributions as being in excess of our cumulative net income for such
purposes and subject to such 10% withholding tax. Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate
equal to the sum of the highest applicable effective tax rate and 10%.
Moreover, the transferee of an interest in a partnership that is engaged in a United States trade or business is generally required to withhold 10% of the
“amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized”
generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer
of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable
transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s
liabilities. For a transfer of interests in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the
transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in
our units.
We have subsidiaries that will be treated as corporations for federal income tax purposes and subject to corporate-level income taxes.
Even though we (as a partnership for United States federal income tax purposes) are not subject to United States federal income tax, some of our operations
are conducted through subsidiaries that are organized as corporations for United States federal income tax purposes. The taxable income, if any, of
subsidiaries that are treated as corporations for United States federal income tax purposes, is subject to corporate-level United States federal income taxes,
which may reduce the cash available for distribution to us and, in turn, to our Unitholders. If the IRS or other state or local jurisdictions were to
successfully assert that these corporations have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, the
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cash available for distribution could be further reduced. The income tax return filings positions taken by these corporate subsidiaries require significant
judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is also required in assessing the timing and
amounts of deductible and taxable items. Despite our belief that the income tax return positions taken by these subsidiaries are fully supportable, certain
positions may be successfully challenged by the IRS, state or local jurisdictions.
We treat each purchaser of units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which
could result in a Unitholder owing more tax and may adversely affect the value of the units.
Because we cannot match transferors and transferees of units and because of other reasons, we have adopted certain methods for allocating depreciation,
depletion and amortization that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods
could adversely affect the amount of tax benefits available to our Unitholders. It also could affect the timing of these tax benefits or the amount of gain
from the sale of units and could have a negative impact on the value of our units or result in audit adjustments to tax returns of our Unitholders. Moreover,
because we have subsidiaries that are organized as C corporations for federal income tax purposes, a successful IRS challenge could result in these
subsidiaries having a greater tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to our
Unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership
of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of
our proration method, and if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our
Unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership
of our units on the first business day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we
generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets and (iii) in
the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date.
Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method
we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and
deduction among our Unitholders.
A Unitholder whose common or preferred units are the subject of a securities loan (e.g. a loan to a short seller to cover a short sale of common or
preferred units) may be considered as having disposed of those units. If so, such Unitholder would no longer be treated for tax purposes as a partner with
respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a Unitholder whose units are the
subject of a securities loan may be considered as having disposed of the loaned units. In that case, the Unitholder may no longer be treated for tax purposes
as a partner with respect to those units during the period of the loan to the short seller, and the Unitholder and may recognize gain or loss from such
disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the
Unitholder and any cash distributions received by the Unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure
their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to
modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies in determining Unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge
these methods or the resulting allocations, and such a challenge could adversely affect the value of our Common Units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or
loss attributable to such assets to the capital accounts of our Unitholders and our general partner. Although we may from time to time consult with
professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets
ourselves using a methodology based on the market value of our Common Units as a means to measure the fair market value of our assets. Our
methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain
Unitholders and our general partner, which may be unfavorable to such Unitholders. Moreover, under our current valuation methods, subsequent purchasers
of our Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser
portion allocated to our intangible assets. The IRS may challenge
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our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain,
loss and deduction between our general partner and certain of our Unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our Unitholders.
It also could affect the amount of gain on the sale of Common Units by our Unitholders and could have a negative impact on the value of our Common
Units or result in audit adjustments to the tax returns of our Unitholders without the benefit of additional deductions.
Unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of
investing in our units.
In addition to United States federal income taxes, the Unitholders may be subject to other taxes, including state and local taxes, unincorporated business
taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or our subsidiaries conduct business or own
property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax
returns and pay state and local income taxes in some or all of these various jurisdictions. Further, Unitholders may be subject to penalties for failure to
comply with those requirements. It is the responsibility of each Unitholder to file all federal, state and local tax returns.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year.
However, our deduction for “business interest” is generally limited to the sum of our business interest income and 30% of our “adjusted taxable income.”
For the purposes of this limitation, adjusted taxable income is computed without regard to any business interest expense or business interest income.
If our “business interest” is subject to limitation under these rules, our Unitholders will be limited in their ability to deduct their share of any interest
expense that has been allocated to them. As a result, Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
The treatment of Energy Transfer Preferred Units is uncertain, and distributions on Energy Transfer Preferred Units (other than Series I Preferred Units)
may not be eligible for the 20% deduction for qualified publicly traded partnership income.
The tax treatment of our Preferred Units is uncertain. With respect to Preferred Units (other than Series I Preferred Units), we will treat Preferred
Unitholders as partners for tax purposes and will treat distributions on such Preferred Units as guaranteed payments for the use of capital that will generally
be taxable to such Preferred Unitholders as ordinary income. Preferred Unitholders of our Preferred Units (other than Series I Preferred Units) will
recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution). Otherwise, except
in the case of our liquidation, Preferred Unitholders of our Preferred Units (other than Series I Preferred Units) are generally not anticipated to share in our
items of income, gain, loss or deduction, nor will we allocate any share of our nonrecourse liabilities to such Preferred Unitholders. If the Energy Transfer
Preferred Units (other than Series I Preferred Units) were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital,
distributions likely would be treated as payments of interest by us to Preferred Unitholders.
Although we expect that much of the income we earn will be eligible for the 20% deduction for qualified publicly traded partnership income for taxable
years beginning after December 31, 2025, the Treasury Regulations provide that income attributable to a guaranteed payment for the use of capital is not
eligible for the 20% deduction for qualified business income. As a result income attributable to a guaranteed payment for use of capital recognized by
holders of our Preferred Units is not eligible for the 20% deduction for qualified business income.
With respect to Series I Preferred Units, we will treat distributions as distributions to a partner and will treat Preferred Unitholders that hold Series I
Preferred Units (the “Series I Preferred Unitholders”) as receiving an allocable share of gross income from us, to the extent we have sufficient gross income
to make such allocations. In the event there is not sufficient gross income to match such distributions, the distributions on the Series I Preferred Units
would reduce the capital accounts of the Series I Preferred Units, requiring a subsequent allocation of income or gain to provide the Series I Preferred Units
with their liquidation preference, if possible. However, if the IRS were to determine that such distributions were guaranteed payments for the use of capital,
the distributions would generally be taxable to each of the Series I Preferred Unitholders as ordinary income and the Series I Preferred Unitholders would
recognize taxable income from the accrual of such guaranteed payment (even in the absence of a contemporaneous cash distribution), as described above
with respect to Preferred Units (other than Series I Preferred Units). If the Series I Preferred Units are not treated as partnership interests, they would likely
constitute indebtedness for tax purposes, and distributions on the Series I Preferred Units likely would be treated as payments of interest by us to such
Series I Preferred Unitholders.
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A Preferred Unitholder will be required to recognize gain or loss on a sale of Energy Transfer Preferred Units equal to the difference between the amount
realized by such Preferred Unitholder and such Preferred Unitholder’s tax basis in the Energy Transfer Preferred Units sold. The amount realized generally
will equal the sum of the cash and the fair market value of other property such Preferred Unitholder receives in exchange for such Energy Transfer
Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests and the rules applicable in determining the
exchanged tax basis of a Series I Preferred Unit received by a Unitholder pursuant to the Crestwood acquisition, the tax basis of a Preferred Unit will
generally be equal to the sum of the cash and the fair market value of other property paid by the Preferred Unitholder to acquire such Energy Transfer
Preferred Units. Gain or loss recognized by a Preferred Unitholder on the sale or exchange of Energy Transfer Preferred Units held for more than one year
generally will be taxable as long-term capital gain or loss. Because Preferred Unitholders will generally not be allocated a share of our items of
depreciation, depletion or amortization, it is not anticipated that such Preferred Unitholders would be required to recharacterize any portion of their gain as
ordinary income as a result of the recapture rules.
Investment in our Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts, and non-United States
persons raises issues unique to them. With respect to Preferred Units (other than Series I Preferred Units), the treatment of guaranteed payments for the use
of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.
With respect to Series I Preferred Units, virtually all of our gross income allocated to tax-exempt investors will be unrelated business taxable income and
will be taxable to them. Distributions to non-United States Preferred Unitholders will be subject to withholding taxes. If the amount of withholding exceeds
the amount of United States federal income tax actually due, non-United States Preferred Unitholders may be required to file United States federal income
tax returns in order to seek a refund of such excess.
All Preferred Unitholders are urged to consult a tax advisor with respect to the consequences of owning Energy Transfer Preferred Units.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
Description of Processes for Assessing, Identifying and Managing Cybersecurity Risks
ITEM 1C. CYBERSECURITY
The information and operational technology infrastructure we use is important to the operation of our business and to our ability to perform day-to-day
operations. In the normal course of business, we may collect and store certain sensitive information of the Partnership, including proprietary and
confidential business information, trade secrets, intellectual property, sensitive third-party and employee information, and certain personally identifiable
information.
The Partnership maintains a shared services cybersecurity program for assessing, identifying and managing material risks from cybersecurity threats. This
program includes processes that are modeled after the National Institute of Standards and Technology’s Cybersecurity Framework and focuses on using
business drivers to guide cybersecurity activities. This program is managed by a team of full-time employees, overseen by our Chief Information Officer,
that are tasked with conducting our day-to-day information technology (“IT”) operations (collectively, the “IT team”). Furthermore, the Partnership
considers cybersecurity risks as part of, and has incorporated its cybersecurity program into, the Partnership’s overall risk management processes. Through
engagement with the guidance of the Federal Bureau of Investigation (FBI), Cybersecurity and Infrastructure Security Agency (CISA), Transportation
Security Administration (TSA) and the U.S. Coast Guard (USCG), we seek to follow industry cybersecurity standards and protect our infrastructure against
cyber attacks from domestic and international threats.
We seek to use a defense-in-depth approach for cybersecurity management, layers of technology, policies and training at all levels of the enterprise
designed to keep the Partnership’s assets secure and operational. We use various processes as part of our efforts to maintain the confidentiality, integrity and
availability of our systems, including security threat intelligence, incident response, identity and access management, supply-chain security assessments,
endpoint extended detection and response protection, network segmentation, data encryption, event monitoring and a Security Operations Center (SOC). In
an effort to validate the effectiveness of our cybersecurity program and assess such program’s compliance with legal and regulatory requirements, we
engage third-party service providers to perform audits, assessments and penetration tests.
Cybersecurity awareness among our employees is promoted with regular training and awareness programs. All employees who have access to our systems
are required to undergo annual cybersecurity training and, each year, our employees must review and acknowledge our cybersecurity policies. Further, our
IT team is trained to understand how to manage, use and protect personally identifiable information. User access controls have been implemented to limit
unauthorized access to sensitive
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information and critical systems. Employees are required to use multifactor authentication and keep their passwords confidential, among other measures.
We recognize that third-party service providers may introduce cybersecurity risks. In an effort to mitigate these risks, before contracting with certain
technology service providers, when possible, we conduct due diligence to evaluate their cybersecurity capabilities. Additionally, we endeavor to include
cybersecurity requirements in our contracts with these providers and endeavor to require them to adhere to security standards and protocols. Further, we
also endeavor to engage with any third-party service providers with access to personally identifiable employee information to evaluate their security
controls.
Finally, the Partnership maintains cybersecurity insurance coverage.
Impact of Risks from Cybersecurity Threats
As of the date of this Annual Report on Form 10-K, though the Partnership and our service providers have experienced certain cybersecurity incidents, we
are not aware of any previous cybersecurity threats that have materially affected the Partnership, either financially or operationally. Cybersecurity incident
response is a component of both the Partnership’s cybersecurity program and the Partnership’s business continuity plans, which are designed to limit
service interruptions and provide for continued business operation in the event of disaster, whether physical, environmental or cyber in nature. However,
we recognize that cybersecurity threats are continually evolving, and there remains a risk that a cybersecurity incident could potentially negatively impact
the Partnership. Despite the implementation of our cybersecurity processes, we cannot guarantee that a significant cybersecurity attack will not occur. A
successful attack on our information system or operational technology system could have significant consequences to the business, including the
interruption of key services that our customers depend on. While we devote resources to our security measures to protect our systems and information,
these measures cannot provide absolute security. Due to the number of acquisitions made by the Partnership over the past few years and the time it takes to
implement technology standards across the enterprise, certain assets may be in different stages of integration and may have incomplete cybersecurity
controls applied. For additional information on cybersecurity risks, see “Item 1A. Risk Factors—Cybersecurity attacks, data breaches and other
disruptions affecting us, our service providers, could materially and adversely affect our business, operations, reputation, and financial results; and —Our
operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.”
Board of Directors’ Oversight and Management’s Role
Our Chief Information Officer oversees the Partnership’s functions of IT, cybersecurity, infrastructure and IT governance (including the Partnership’s IT
team) and has more than 35 years of experience leading business technology functions. The Partnership’s IT team is responsible for our efforts to comply
with applicable cybersecurity standards, establish effective cybersecurity protocols and protect the integrity, confidentiality and availability of our IT
infrastructure. The members of this team have over 50 years of combined experience in the field of IT, including 20 years dedicated to cybersecurity, and
hold various certifications, including Global Industrial Cyber Security Professional (GICSP), Certified Information Systems Security Professional (CISSP)
and Certified Ethical Hacker (CEH) certifications. This team is responsible for cybersecurity threat prevention, detection, mitigation and remediation for
the combined organization. Our cyber incident response plan requires IT team members who detect suspicious activity in our IT environment to escalate
that activity to a supervisor who then evaluates the threat. If necessary, the suspicious activity is reported to the Chief Information Officer. Management
(including representatives from the legal, human resources, IT and corporate security departments) is notified by the IT team whenever a discovered
cybersecurity incident may potentially have a significant impact on our business operations.
The Partnership’s Board of Directors has delegated the responsibility for the oversight of cybersecurity risks to the Audit Committee, which is ultimately
responsible for assessing and managing the Partnership’s material risks from cybersecurity threats. The IT team provides periodic cybersecurity program
updates to senior management and to the Audit Committee. Management also updates the Audit Committee as new risks are identified and the steps taken
to mitigate such risks.
ITEM 2. PROPERTIES
A description of our properties is included in “Item 1. Business.” In addition, we own office buildings for our executive offices in Dallas, Texas and office
buildings in Newton Square, Pennsylvania; Houston, Texas and San Antonio, Texas. While we may require additional office space as our business expands,
we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on
commercially reasonable terms as needed.
We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of our properties are subject to liabilities and
leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial
encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our
business, taken as a whole. In addition, we believe that
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we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have
obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which
relate to ownership of our properties or the operations of our business.
Substantially all of our pipelines, which are described in “Item 1. Business,” are constructed on rights-of-way granted by the apparent record owners of the
property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way
grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities
in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our
pipelines were built were purchased in fee. We also own and operate multiple natural gas and NGL storage facilities and own or lease other processing,
treating and conditioning facilities in connection with our midstream operations.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and
Supplementary Data” in this Annual Report on Form 10-K for the year ended December 31, 2023.
Additionally, we have received notices of violations and potential fines under various federal, state and local provisions relating to the discharge of
materials into the environment or protection of the environment. While we believe that even if any one or more of the following environmental proceedings
were decided against us, it would not be material to our financial position, results of operations or cash flows, we are required to report environmental
governmental proceedings if we reasonably believe that such proceedings reasonably could result in monetary sanctions in excess of $0.3 million.
ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater. The
plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws, and/or deceptive
business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief,
punitive damages and attorneys’ fees.
As of March 31, 2023, Sunoco Defendants are defendants in two cases: one case initiated by the State of Maryland and one by the Commonwealth of
Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco and Sunoco Partners Marketing & Terminals L.P., now known as Energy
Transfer Marketing & Terminals L.P.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess
of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations
during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material adverse effect on the
Partnership’s consolidated financial position.
In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known as
the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was
pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to explain
why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in their
submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021. FERC
issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. On January 25, 2022, the chief judge assigned an
administrative law judge and set a timeline for a prehearing conference.
On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District of
Texas seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before an administrative law judge). Also
on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC administrative law judge pending the
outcome of the federal district court case. On May 24, 2022, the District Court ordered a stay of the FERC’s enforcement case and the District Court case
pending the resolution of two cases pending before the United States Supreme Court. Arguments were heard in those cases on November 7, 2022. On April
14, 2023, the United States Supreme Court held against the government in both cases, finding that the federal district courts had jurisdiction to hear those
suits and to resolve the parties’ constitutional challenges. The cases were remanded to the federal district courts for further proceedings.
On September 13, 2023 the District Court ordered that the District Court case would be stayed pending the resolution of another case pending before the
United States Supreme Court and that the FERC enforcement case would remain stayed. Energy Transfer and Rover intend to vigorously defend this claim.
On November 13, 2023, the FERC appealed the District Court order to the United States Court of Appeals for the Fifth Circuit. On December 11, 2023,
FERC filed a motion to withdraw that
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appeal, which the Fifth Circuit granted on December 12, 2023. The FERC and District Court proceedings remain stayed pending resolution of the case
pending before the United States Supreme Court.
In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling mud at
the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigation. Enforcement
Staff has provided Rover with a notice pursuant to Section 1b.19 of the FERC’s regulations that Enforcement Staff intends to recommend that the FERC
pursue an enforcement action against Rover and the Partnership. The company disagrees with Enforcement Staff’s findings and intends to vigorously
defend against any potential penalty. On December 16, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN17-4-
000), ordering Rover to show cause why it should not be found to have violated Section 7(e) of the NGA, Section 157.20 of FERC’s regulations, and the
Rover Pipeline Certificate Order, and assessed civil penalties of $40 million.
Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and Energy
Transfer filed their surreply to this order on May 13, 2022. FERC has taken no further action on the case since that time. Any and all losses, including any
fines and penalties from government agencies, resulting from the general contractor’s alleged actions in conducting such HDD operations are subject to
indemnity rights in favor of Rover and the Partnership. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment
of the potential outcome or range of potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the
penalty proposed by Enforcement Staff and intends to vigorously defend itself against the subject claims.
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants
(collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to
permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9, 2019,
the Fifth District court of appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme Court. On
April 22, 2020, the Ohio Supreme Court granted the review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to the Ohio trial
court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act but remanded to
the trial court to determine whether any of the allegations fell outside the scope of the waiver. On remand, the Ohio EPA voluntarily dismissed four of the
other five defendants and dismissed one of its counts against Rover. In its Fourth Amended Complaint, the Ohio EPA removed all paragraphs that alleged
violations by the four dismissed defendants, including those where the dismissed defendants were alleged to have acted jointly with Rover or others. At a
June 2, 2022, status conference, the trial judge set a schedule for Rover and the other remaining defendant to file motions to dismiss the Fourth Amended
Complaint. On August 1, 2022, Rover and the other remaining defendant each filed their respective motions. Briefing on those motions was completed on
November 4, 2022. By order issued on October 20, 2023, the trial judge dismissed the Ohio EPA’s Fourth Amended Petition. On November 17, 2023, the
State of Ohio appealed the trial judge’s decision to Ohio’s Fifth District Court of Appeals. The State filed its initial brief on January 8, 2024 and Energy
Transfer’s and Rover’s responsive brief is currently due February 20, 2024.
In January 2019, we received notice from the DOJ on behalf of the EPA that a civil penalty enforcement action was being pursued under the Clean Water
Act for an estimated 450 barrel crude oil release from the Mid Valley Pipeline operated by SPLP and owned by Mid Valley. The release purportedly
occurred in October 2014 on a nature preserve located in Hamilton County, Ohio, near Cincinnati, Ohio. After discovery and notification of the release,
SPLP conducted substantial emergency response, remedial work and primary restoration in three phases and the primary restoration has been
acknowledged to be complete. Operation and maintenance (O&M) activities will continue for several years. In December of 2019, SPLP reached an
agreement in principal with the EPA regarding payment of a civil penalty which will be subject to public comment. The DOJ, on behalf of United States
Department of Interior Fish and Wildlife, and the Ohio Attorney General, on behalf of the Ohio EPA, along with technical representatives from those
agencies have resolved in principal the natural resource damage assessment claims related to state endangered species and compensatory restoration.
On February 3, 2022, the State of New Mexico, ex rel. Hector Balderas, Attorney General filed a complaint against ETO, Transwestern, Kinder Morgan,
Inc., El Paso Natural Gas LLC and Northwest Pipeline, LLC in Cause No. D-101-CV-2022-00174 in the First Judicial District Court, County of Santa Fe,
State of New Mexico, seeking to recover statewide damages for contamination with PCBs used for decades by the oil and gas industry in the operation and
maintenance of pipeline infrastructure. The complaint alleges discharge or release of PCBs into the natural environment from compressor stations in
connection with the operation of the Transwestern Pipeline. Given the early stage of this proceeding, the Partnership is unable at this time to provide an
assessment of the potential outcome or range of potential liability, if any.
On June 29, 2022, near Henderson, Tennessee, a Mid Valley mowing contractor struck an exposed section of the 22-inch diameter Hornsby to Denver line
segment while mowing. The brush cutter mowing implement cut open the pipeline and released an estimated 4,345 barrels of crude oil into the surrounding
area. Approximately 3,343 barrels of crude oil were
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recovered during initial remediation activities with the remaining volume contained within the materials removed and disposed of in accordance with
applicable environmental laws and regulations. Corrective action was being completed pursuant to the Tennessee DEC’s Division of Remediation -
Voluntary Action Program (“VAP”) and on May 23, 2023, Mid Valley received a No Further Action letter from the Tennessee Department of Environment
and Conservation (“TN DEC”) for the corrective action work related to the incident. Additional environmental work was completed in late August 2023
along the pipeline right-of-way to address a small oil seep which required soil removal and site restoration. The TN DEC was notified and a follow-up
report will be submitted to the agency documenting completion. Mid Valley received a Notice of Federal Interest regarding the incident and is awaiting
final invoicing from the federal agencies (United States Environmental Protection Agency and United States Fish and Wildlife Service) and their
consultants related to the incident. Mid Valley has also supplied PHMSA with information as requested. On October 13, 2023, Mid Valley received a
Notice of Proposed Safety Order (NOPSO) from PHMSA related to this incident and other historical incidents on the Mid Valley system. Several actions
over the next six months are requested in the NOPSO and a response is due within 30 days. No other government agency action has occurred. Groundwater
monitoring wells were abandoned on June 12, 2023, which concluded environmental related activities associated with the incident site. No injuries resulted
from the incident.
On June 26, 2023, Plaintiffs Michael and Cecilia Weinman (collectively, “Plaintiffs”) filed suit in Chester County, Tennessee, against Mid Valley, Energy
Transfer Crude Marketing LLC, Energy Transfer Crude Oil Company, LLC, Energy Transfer Employee Management LLC, Energy Transfer Marketing &
Terminals L.P., Energy Transfer LP, (collectively, the “Energy Transfer Defendants”) and other unnamed defendants asserting claims for negligence,
trespass, and other tort claims and alleging damage to their property stemming from the crude oil release. Plaintiffs alleged actual monetary damages and
punitive damages totaling $380 million. The Energy Transfer Defendants were served on or around July 5, 2023, and timely filed a notice of removal of the
lawsuit to federal court in the Western District of Tennessee—Eastern Division on August 2, 2023. On August 8, 2023, Plaintiffs filed a notice of voluntary
dismissal of their lawsuit without prejudice.
On November 29, 2023, the United States Coast Guard issued the final invoice for all federal expenses related to the incident response in the amount of
$90,000. The expenses have been validated and sent for payment.
The Energy Transfer Defendants cannot predict the ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.
On October 13, 2023, Mid Valley received a Notice of Proposed Safety Order (“NOPSO”) from the PHMSA related to various historical accidents and
complaints reported to PHMSA on the Mid Valley system. The NOPSO requests that Mid Valley perform several proposed corrective measures within six
months of receipt of a Safety Order; however, in response, Mid Valley requested that PHMSA engage in informal consultations prior to issuing a Safety
Order in an effort for the parties to potentially enter into a Consent Agreement and Order. Informal consultation is underway. In the event a Consent
Agreement and Order is not reached between the parties during this process, Mid Valley may request a Hearing on the NOPSO. It is too early to predict the
outcome, timeline, or costs associated with this administrative action.
On October 28, 2022, the EPA issued a Notice of Proposed Debarment (“NPD”) arising from SPLP’s and ETC Northeast Pipeline, LLC’s nolo contendere
plea agreements and convictions for violations of Pennsylvania’s Clean Streams Law related to the Revolution and Mariner 2 pipelines. The following
entities were proposed for debarment: (1) SPLP (pleading entity); (2) ETC Northeast Pipeline, LLC (pleading entity); (3) Energy Transfer LP; (4)
SemGroup LLC; and (5) LE GP, LLC. The NPD presently prevents the named entities from pursuing or renewing Federal government contracts or Federal
financial assistance agreements. We are engaging with the EPA to address the EPA’s concerns. Currently, none of the entities named in the NPD are party to
any Federal government contracts or Federal financial assistance agreements.
On June 15, 2023, PHMSA issued a Notice of Probable Violation, Proposed Civil Penalty, and Proposed Compliance Order (collectively “NOPV”), CPF 4-
2023-011-NOPV, identifying three probable violations with compliance order actions associated with two of them and civil penalties proposed in an
amount totaling $2,473,912. The NOPV related to a PHMSA Accident Investigation Division investigation of a pigging incident which occurred on March
26, 2020 at the Partnership’s Borcher Station in Kansas and resulted in a fatality. The Partnership challenged PHMSA’s alleged violations and related civil
penalties and compliance order actions contained in the NOPV, and requested an administrative hearing, which is set for April 24, 2024 before a PHMSA
Presiding Official.
On August 31, 2023, the United States Department of Justice filed suit in the District Court for the Southern District of Texas (Corpus Christi Division)
captioned as United States v. Energy Transfer (R&M), LLC et al. Civil Action No. 2:23-cv-214, against Sunoco and two other parties seeking to recover
past CERCLA response costs allegedly incurred by the EPA in excess of $500,000 and certain declaratory relief related to compliance. Suntide Refining
Company (Sunoco as successor) is alleged to have arranged for the transport and disposal of refinery wastes containing hazardous substances at the Brine
Service Company Superfund Site in Corpus Christi, Nueces County, TX. At this time, we cannot determine the likelihood of any liability in this
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matter; however, Sunoco intends to defend and dispute the allegations of the lawsuit, including but not limited to the joint and several liability
determination sought. This lawsuit is included among the matters described in our discussion of our other environmental remediation matters. Please see
Note 11 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Not applicable.
ITEM 4. MINE SAFETY DISCLOSURES
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ITEM 5. MARKET FOR REGISTRANT’S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES
PART II
Description of Units
As of February 9, 2024, there were 11,242 holders of record of our common units, which number does not separately account for individual participants in
securities positions listings. Common units represent limited partner interests in us that entitle the holders to the rights and privileges specified in Energy
Transfer’s Partnership Agreement.
As of December 31, 2023, limited partners own an aggregate 99.9% limited partner interest in us. Our General Partner owns an aggregate 0.1% general
partner interest in us. Our common units are registered under the Exchange Act, and are listed for trading on the NYSE under the ticker symbol “ET.” Each
holder of a common unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or
group (other than our General Partner and its affiliates) owns beneficially 20% or more of all common units, any Common Units owned by that person or
group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of unitholders (unless otherwise required
by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The common
units are entitled to distributions of Available Cash as described in “Cash Distribution Policy.”
Energy Transfer Class A Units
As of February 9, 2024, the Partnership had outstanding 833,543,364 Class A units (“Energy Transfer Class A Units”) representing limited partner interests
in the Partnership to the General Partner. The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units, as a single
class, except as required by law. Additionally, Energy Transfer’s Partnership Agreement provides that, under certain circumstances, upon the issuance by
the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership common units, the Partnership
will issue to any holder of Energy Transfer Class A Units additional Energy Transfer Class A Units such that the holder maintains a voting interest in the
Partnership that is identical to its voting interest in the Partnership prior to such issuance of common units. The Energy Transfer Class A Units are not
entitled to distributions and otherwise have no economic attributes.
Energy Transfer Preferred Units
As of December 31, 2023, the Partnership had the following series of preferred units outstanding:
Series of Preferred Units
Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred
Units
Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred
Units
Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred
Units
Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred
Units
Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred
Units
Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units
Series I Fixed Rate Perpetual Preferred Units
Units Issued and
Outstanding
Liquidation
Preference per Unit
Date Issued
(1)
950,000 $
550,000
18,000,000
17,800,000
32,000,000
500,000
1,484,780
900,000
41,464,179
1,000
1,000
25
25
25
1,000
1,000
1,000
9.1273
April 2021
April 2021
April 2021
April 2021
April 2021
April 2021
April 2021 and
(2)
December 2021
June 2021
(3)
November 2023
(1)
In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1 to our consolidated financial statements included in “Item 8. Financial
Statements and Supplementary Data,” all of ETO’s previously outstanding preferred units were converted to Energy Transfer Preferred Units with
identical distribution and redemption rights.
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(2)
(3)
In connection with the Enable acquisition in December 2021, Energy Transfer issued 384,780 additional Series G Preferred Units. The total reflected
above includes these additional Series G Preferred Units, as well as the 1,100,000 Series G Preferred Units originally issued in the Rollup Mergers.
The Series I Preferred Units were issued in connection with the Crestwood acquisition in November 2023.
In February 2024, the Partnership redeemed all of the Series C Preferred Units and Series D Preferred Units. The Partnership expects to redeem all of the
Series E Preferred Units in May 2024.
Additional information for each series of outstanding preferred units, including information on distributions and redemption, is available in Note 8 to our
consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."
Cash Distribution Policy
General. Energy Transfer will distribute all of its “Available Cash” to its Unitholders and its General Partner within 50 days following the end of each
fiscal quarter.
Definition of Available Cash. Available Cash is defined in the Partnership Agreement and generally means, with respect to any calendar quarter, all cash
on hand at the end of such quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:
•
•
•
provide for the proper conduct of its business;
comply with applicable law and/or debt instrument or other agreement; and
provide funds for distributions to Unitholders and its General Partner in respect of any one or more of the next four quarters.
Recent Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.
Securities Authorized for Issuance Under Equity Compensation Plans
For information on the securities authorized for issuance under Energy Transfer’s equity compensation plans, see “Item 12. Security Ownership of Certain
Beneficial Owners and Management and Related Unitholder Matters.”
ITEM 6. [RESERVED]
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
(Tabular dollar and unit amounts, except per unit data, are in millions)
Energy Transfer LP is a Delaware limited partnership whose common units are publicly traded on the NYSE under the ticker symbol “ET.”
The following discussion of our consolidated financial condition and results of operations for the years ended December 31, 2023 and 2022 should be read
in conjunction with our consolidated financial statements and accompanying notes thereto included in “Item 8. Financial Statements and Supplementary
Data” of this report. This discussion includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially
from the statements we make in this section due to a number of factors that are discussed in “Item 1A. Risk Factors” of this report.
Discussion and analysis of matters pertaining to the year ended December 31, 2021 and year-to-year comparisons between the years ended December 31,
2022 and 2021 are not included in this Form 10-K, but can be found under Part II, Item 7 of our annual report on Form 10-K for the year ended
December 31, 2022 that was filed with the SEC on February 17, 2023.
Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “Energy Transfer” mean Energy Transfer LP and its
consolidated subsidiaries.
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OVERVIEW
The primary activities in which we are engaged, which are located in the United States, are as follows:
•
natural gas operations, including the following:
•
•
natural gas midstream and intrastate transportation and storage;
interstate natural gas transportation and storage; and
•
crude oil, NGL and refined products transportation, terminalling and acquisition and marketing activities as well as NGL storage and fractionation
services.
In addition, we own investments in other businesses, including Sunoco LP and USAC, both of which are master limited partnerships.
Energy Transfer derives cash flows from distributions related to its investment in its subsidiaries, including Sunoco LP and USAC. The amount of cash that
our subsidiaries distribute to us is based on earnings from their respective business activities and the amount of available cash. Energy Transfer’s primary
cash requirements are for distributions to its partners, general and administrative expenses and debt service requirements. Energy Transfer distributes its
available cash remaining after satisfaction of the aforementioned cash requirements to its Unitholders on a quarterly basis.
We expect our subsidiaries to utilize their resources, along with cash from their operations, to fund their announced growth capital expenditures and
working capital needs; however, Energy Transfer may issue debt or equity securities from time to time as we deem prudent to provide liquidity for new
capital projects of our subsidiaries or for other partnership purposes.
General
Our primary objective is to increase the level of our distributable cash flow to our Unitholders over time by pursuing a business strategy that is currently
focused on growing our subsidiaries’ natural gas and liquids businesses through, among other things, pursuing certain construction and expansion
opportunities relating to our subsidiaries’ existing infrastructure and acquiring certain strategic operations and businesses or assets. The actual amounts of
cash that we will have available for distribution will primarily depend on the amount of cash our subsidiaries generate from their operations.
Our reportable segments are as follows:
•
•
intrastate transportation and storage;
interstate transportation and storage;
• midstream;
• NGL and refined products transportation and services;
•
•
•
•
crude oil transportation and services;
investment in Sunoco LP;
investment in USAC; and
all other.
Recent Developments
Crestwood Acquisition
On November 3, 2023, Energy Transfer acquired Crestwood, which owns gathering and processing assets located in the Williston, Delaware and Powder
River basins. Under the terms of the merger agreement, holders of Crestwood common units received 2.07 Energy Transfer common units for each
Crestwood common unit held by them (the “Common Unit Merger Consideration”). Additionally, each outstanding Crestwood preferred unit was, at the
election of the holder of such Crestwood preferred unit, either, (i) converted into a Series I Preferred Unit, which is a new preferred unit of Energy Transfer
that has substantially similar terms, including with respect to economics and structural protections, as the Crestwood preferred units; (ii) redeemed in
exchange for $9.857484 in cash plus accrued and unpaid distributions to the date of such redemption; or (iii) converted into a Crestwood common unit at
the then-applicable conversion ratio of one Crestwood common unit for ten Crestwood preferred units, and such Crestwood common units then received
the Common Unit Merger Consideration.
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In total, consideration issued in the transaction included approximately 216 million Energy Transfer common units, 41 million Series I Preferred Units and
$300 million in cash. Concurrent with the closing of the Crestwood acquisition, the Partnership assumed $2.85 billion aggregate principal amount of
Crestwood senior notes and terminated its revolving credit facility, which included the repayment of $613 million in outstanding borrowings.
Lotus Midstream Acquisition
On May 2, 2023, Energy Transfer acquired Lotus Midstream for total consideration of $1.50 billion, including working capital. Consideration included
$930 million in cash and approximately 44.5 million newly issued Energy Transfer common units, which had an aggregate acquisition-date fair value of
$574 million. Lotus Midstream owns and operates Centurion Pipeline Company LLC, an integrated crude midstream platform located in the Permian
Basin.
Sunoco LP’s Acquisitions and Divestiture
On January 22, 2024, Sunoco LP entered into a definitive agreement with NuStar to acquire NuStar in an all-equity transaction valued at approximately
$7.3 billion, including assumed debt. Under the terms of the agreement, NuStar common unitholders will receive 0.4 Sunoco common units for each
NuStar common unit. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute crude oil, refined
products, renewable fuels, ammonia and specialty liquids. The transaction is expected to close in the second quarter of 2024, subject to customary closing
conditions.
On January 11, 2024, Sunoco LP entered into a definitive agreement with 7-Eleven, Inc. to sell 204 convenience stores located in West Texas, New Mexico
and Oklahoma for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale, Sunoco LP will
also amend its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. The transaction is expected to
close promptly upon receipt of regulatory approvals and satisfaction of customary closing conditions.
On January 11, 2024, Sunoco LP also announced that it will acquire liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from Zenith
Energy for €170 million including working capital. The transaction is expected to close in the first quarter of 2024, subject to customary closing conditions.
On May 1, 2023, Sunoco LP completed the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy for
$111 million, including working capital.
Regulatory Update
Interstate Natural Gas Transportation Regulation
Rate Regulation
Effective January 2018, the 2017 Tax Cuts and Jobs Act (the “Tax Act”) changed several provisions of the federal tax code, including a reduction in the
maximum corporate tax rate. On March 15, 2018, in a set of related proposals, the FERC addressed treatment of federal income tax allowances in regulated
entity rates. The FERC issued a Revised Policy Statement on Treatment of Income Taxes (“Revised Policy Statement”) stating that it will no longer permit
master limited partnerships to recover an income tax allowance in their cost-of-service rates. The FERC issued the Revised Policy Statement in response to
a remand from the United States Court of Appeals for the District of Columbia Circuit in United Airlines v. FERC, in which the court determined that the
FERC had not justified its conclusion that a pipeline organized as a master limited partnership would not “double recover” its taxes under the current policy
by both including an income-tax allowance in its cost of service and earning a return on equity calculated using the discounted cash flow methodology. On
July 18, 2018, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from arguing and
providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result
in a double-recovery of investors’ income tax costs. On July 31, 2020, the United States Court of Appeals for the District of Columbia Circuit issued an
opinion upholding the FERC’s decision denying a separate master limited partnership recovery of an income tax allowance and its decision not to require
the master limited partnership to refund accumulated deferred income tax balances. In light of the rehearing order’s clarification regarding an individual
entity’s ability to argue in support of recovery of an income tax allowance and the court’s subsequent opinion upholding denial of an income tax allowance
to a master limited partnership, the impact of the FERC’s policy on the treatment of income taxes on the rates we can charge for FERC-regulated
transportation services is unknown at this time.
Even without application of the FERC’s rate making-related policy statements and rulemakings, the FERC or our shippers may challenge the cost-of-
service rates we charge. The FERC’s establishment of a just and reasonable rate is based on many components, including ROE and tax-related components,
but also other pipeline costs that will continue to affect FERC’s determination of just and reasonable cost-of-service rates. Moreover, we receive revenues
from our pipelines based on a variety
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of rate structures, including cost-of-service rates, negotiated rates, discounted rates and market-based rates. Many of our interstate pipelines, such as Tiger
Pipeline, Midcontinent Express Pipeline and Fayetteville Express Pipeline, have negotiated market rates that were agreed to by customers in connection
with long-term contracts entered into to support the construction of the pipelines. Other systems, such as Florida Gas Transmission Pipeline, Transwestern
and Panhandle, have a mix of tariff rate, discount rate and negotiated rate agreements. The revenues we receive from natural gas transportation services we
provide pursuant to cost-of-service based rates may decrease in the future as a result of changes to FERC policies, combined with the reduced corporate
federal income tax rate established in the Tax Act. The extent of any revenue reduction related to our cost-of-service rates, if any, will depend on a detailed
review of all of our cost-of-service components and the outcomes of any challenges to our rates by the FERC or our shippers.
On July 18, 2018, the FERC issued a final rule establishing procedures to evaluate rates charged by the FERC-jurisdictional gas pipelines in light of the
Tax Act and the FERC’s Revised Policy Statement. By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates
pursuant to Section 5 of the NGA to determine whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August
30, 2019, Panhandle filed a general rate proceeding under Section 4 of the NGA. The NGA Section 5 and Section 4 proceedings were consolidated by order
of the Chief Judge on October 1, 2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the
FERC issued its order on the initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for
rehearing of FERC’s order on the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed
these orders to the United States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission
also subsequently appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s
appeals and stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On
September 25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing.
Panhandle has timely filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed
a limited request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by
operation of law on November 27, 2023. On November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings, which
has been protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it modified
certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review with the Court
of Appeals regarding the January 5, 2024 order.
Pipeline Certification
The FERC issued a Notice of Inquiry on April 19, 2018 (“Pipeline Certification NOI”), thereby initiating a review of its policies on certification of natural
gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in
1999, that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI (“2021 NOI”),
reopening its review of the 1999 Policy Statement. Comments on the 2021 NOI were due on May 26, 2021; we filed comments in the FERC proceeding. In
September 2021, FERC issued a Notice of Technical Conference on Greenhouse Gas Mitigation related to natural gas infrastructure projects authorized
under Sections 3 and 7 of the NGA. A technical conference was held on November 19, 2021, and post-technical conference comments were submitted to
the FERC on January 7, 2022.
On February 18, 2022, the FERC issued two new policy statements: (1) an Updated Policy Statement on the Certification of New Interstate Natural Gas
Facilities and (2) a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (“2022 Policy
Statements”), to be effective that same day. On March 24, 2022, the FERC issued an order designating the 2022 Policy Statements as draft policy
statements, and requested further comments. The FERC will not apply the now draft 2022 Policy Statements to pending applications or applications to be
filed at FERC until it issues any final guidance on these topics. Comments on the 2022 Policy Statements were due on April 25, 2022, and reply comments
were due on May 25, 2022. We are unable to predict what, if any, changes may be proposed as a result of the 2022 Policy Statements that might affect our
natural gas pipeline or LNG facility projects, or when such new policies, if any, might become effective. We do not expect that any change in these policy
statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
Interstate Common Carrier Regulation
Liquids pipelines transporting in interstate commerce are regulated by FERC as common carriers under the Interstate Commerce Act (“ICA”). Under the
ICA, the FERC utilizes an indexing rate methodology which, as currently in effect, allows common carriers to change their rates within prescribed ceiling
levels that are tied to changes in the Producer Price Index for Finished Goods, or PPI-FG. Many existing pipelines utilize the FERC liquids index to change
transportation rates annually. The
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indexing methodology is applicable to existing rates, with the exclusion of market-based rates. The FERC’s indexing methodology is subject to review
every five years.
On December 17, 2020, FERC issued an order establishing a new index of PPI-FG plus 0.78%. The FERC received requests for rehearing of its December
17, 2020 order and on January 20, 2022, granted rehearing and modified the oil index. Specifically, for the five-year period commencing July 1, 2021 and
ending June 30, 2026, FERC-regulated liquids pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG minus
0.21%. FERC directed liquids pipelines to recompute their ceiling levels for July 1, 2021 through June 30, 2022, as well as the ceiling levels for the period
July 1, 2022 to June 30, 2023, based on the new index level. Where an oil pipeline’s filed rates exceed its ceiling levels, FERC ordered such oil pipelines to
reduce the rate to bring it into compliance with the recomputed ceiling level to be effective March 1, 2022. Some parties sought rehearing of the January 20
order with FERC, which was denied by FERC on May 6, 2022. Certain parties have appealed the January 20 and May 6 orders. Such appeals remain
pending at the D.C. Circuit.
On October 20, 2022, the FERC issued a policy statement on the Standard Applied to Complaints Against Oil Pipeline Index Rate Changes to establish
guidelines regarding how the FERC will evaluate shipper complaints against oil pipeline index rate increases. Specifically, the policy statement adopted the
proposal in the FERC’s earlier Notice of Inquiry issued on March 25, 2020 to eliminate the “Substantially Exacerbate Test” as the preliminary screen
applied to complaints against index rate increases and instead adopt the proposal to apply the “Percentage Comparison Test” as the preliminary screen for
both protests and complaints against index rate increases. At this time, we cannot determine the effect of a change in the FERC’s preliminary screen for
complaints against index rates changes, however, a revised screen would result in a threshold aligned with the existing threshold for protests against index
rate increases. Any complaint or protest raised by a shipper could materially and adversely affect our financial condition, results of operations or cash
flows.
Air Quality Standards
The EPA recently finalized its Good Neighbor Plan (the “Plan”) which seeks to reduce nitrogen oxide pollution from power plants and other industrial
facilities from 23 upwind states which the EPA determined is contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and
interfering with maintenance of the 2015 ozone NAAQS in downwind states. As part of the Plan, the EPA announced that it would be issuing prescriptive
emission standards for several sectors, including certain new and existing internal combustion engines of a certain size used in pipeline transportation of
natural gas. The EPA’s final rule was to become effective on August 4, 2023, and the prescribed emission standards were scheduled to be effective in 2026;
however, of the nine states impacted within the Partnership’s footprint, effectiveness of the rule is currently stayed in six states and pending a decision on a
stay in three other states. Additionally, other operators and industry groups have challenged the Plan and sought a stay in the D.C. Circuit. Although the
stay was denied, it was promptly followed by the filing of an emergency stay application with the U.S. Supreme Court, which will be heard on February 19,
2024, all while EPA has proposed adding five more states to the Plan. The Partnership currently estimates that the final rule would require retrofitting or
replacement of approximately 192 engines in its interstate and intrastate natural gas transportation and storage operations. The Partnership is involved in
challenging application of the Plan in the nine states impacted within its footprint. Compliance with the Plan (if implementation is not stayed or otherwise
delayed) will still require substantial capital expenditures which could adversely affect our business in future periods. However, at this time, we are still
assessing the potential costs of this rule and, given uncertainties resulting from the multiple legal challenges filed against the Plan in various states, in the
DC Circuit and the U.S. Supreme Court, we cannot predict with any certainty what the final costs of compliance for the Plan for the Partnership ultimately
may be.
Trends and Outlook
Overall, we believe the Partnership’s outlook is strong, as it has a stable business that has demonstrated its ability to manage through various market cycles.
We expect future growth to be supported by production improvements, improved market conditions, and increased utilization of our existing assets, as well
as strong domestic and international demand for our products.
While we anticipate that current and projected commodity prices and the related impact to activity levels in both the upstream and midstream sectors will
continue to impact our business, we cannot predict the ultimate magnitude of that impact and expect it to be varied across our operations, depending on the
region, customer, type of service, contract term and other factors.
In addition, the U.S. economy has experienced higher-than-average inflation in recent years, which has resulted in higher costs for labor, services, and
materials. Our suppliers and customers also face inflationary pressures, and our throughput volumes may be impacted if producers are constrained. While
the rate and scope of various inflationary factors may increase our operating costs and capital expenditures materially, we anticipate that any such impacts
would be recoverable in the prices of our services.
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Ultimately, the extent to which our business will be impacted by future market developments depends on factors beyond our control, which are highly
uncertain and cannot be predicted. In response to the recent market volatility and uncertainties, we have reduced growth capital spending in recent years,
and we expect to continue to maintain a prudent level of growth capital spending going forward. See “Liquidity and Capital Resources” for additional
information on our capital expenditures over the last two years and our forecasted capital expenditures for 2024.
We currently have ample liquidity to fund our business, and we do not anticipate any liquidity concerns in the immediate future (see “Liquidity and Capital
Resources”). In addition, we continue to have access to the debt capital markets on generally favorable terms. We will continue to evaluate growth projects
and acquisitions as such opportunities may be identified in the future.
In addition to the trends and outlook discussed above with respect to the Partnership’s existing business and finances, we also anticipate that the Partnership
will continue to increase its focus on the development of alternative energy projects. The Partnership has announced several such projects recently and will
continue to pursue opportunities aimed at continuing to reduce its environmental footprint throughout its operations.
Results of Operations
We report Segment Adjusted EBITDA and consolidated Adjusted EBITDA as measures of segment performance. We define Segment Adjusted EBITDA
and consolidated Adjusted EBITDA as total Partnership earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items,
such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains
and losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt and
other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory adjustments that are excluded from the
calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts are
unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period.
Segment Adjusted EBITDA and consolidated Adjusted EBITDA reflect amounts for unconsolidated affiliates based on the same recognition and
measurement methods used to record equity in earnings of unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the
same items with respect to the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted
EBITDA, such as interest, taxes, depreciation, depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted
EBITDA related to unconsolidated affiliates, such exclusion should not be understood to imply that we have control over the operations and resulting
revenues and expenses of such affiliates. We do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such
affiliates. The use of Segment Adjusted EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited
accordingly.
Segment Adjusted EBITDA, as reported for each segment in the following table, is analyzed in the section titled “Segment Operating Results.” Adjusted
EBITDA is a non-GAAP measure used by industry analysts, investors, lenders and rating agencies to assess the financial performance and the operating
results of the Partnership’s fundamental business activities and should not be considered in isolation or as a substitution for net income, income from
operations, cash flows from operating activities or other GAAP measures.
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Year Ended December 31, 2023 Compared to the Year Ended December 31, 2022
Consolidated Results
Segment Adjusted EBITDA:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
Investment in Sunoco LP
Investment in USAC
All other
Adjusted EBITDA (consolidated)
Reconciliation of net income to Adjusted EBITDA:
Net income
Depreciation, depletion and amortization
Interest expense, net of interest capitalized
Income tax expense
Impairment losses and other
Gains on interest rate derivatives
Non-cash compensation expense
Unrealized gains on commodity risk management activities
Inventory valuation adjustments (Sunoco LP)
Gains on extinguishments of debt
Adjusted EBITDA related to unconsolidated affiliates
Equity in earnings of unconsolidated affiliates
Non-operating litigation-related loss
Other, net
Adjusted EBITDA (consolidated)
Years Ended December 31,
2022
2023
Change
1,111 $
2,009
2,525
3,894
2,681
964
512
2
13,698 $
1,396 $
1,753
3,210
3,025
2,187
919
426
177
13,093 $
Years Ended December 31,
2022
2023
Change
5,294 $
4,385
2,578
303
12
(36)
130
(3)
114
(2)
691
(383)
627
(12)
13,698 $
5,868 $
4,164
2,306
204
386
(293)
115
(42)
(5)
—
565
(257)
—
82
13,093 $
(285)
256
(685)
869
494
45
86
(175)
605
(574)
221
272
99
(374)
257
15
39
119
(2)
126
(126)
627
(94)
605
$
$
$
$
Net Income. For the year ended December 31, 2023 compared to the prior year, net income decreased $574 million, or approximately 10%, primarily due to
the recognition of a $627 million non-operating litigation-related loss, as well as decreases in gains on interest rate derivatives and increases in interest
expense, income tax expense and depreciation, depletion and amortization expense; each of these items is discussed further below. The impacts of these
decreases were partially offset by an increase in equity in earnings of unconsolidated affiliates, as well as the impacts of impairment and other losses
recognized in the prior period; these items are also discussed further below. The change to net income also reflects changes in Adjusted EBITDA, which
are summarized below and discussed in more detail in “Segment Operating Results.”
Adjusted EBITDA (consolidated). For the year ended December 31, 2023 compared to the prior year, Adjusted EBITDA increased $605 million primarily
due to favorable results in multiple segments. The most significant increase was in our NGL and refined products transportation and services segment,
which reflected higher throughput and contractual rates, as well as favorable impacts from optimization. Our crude oil transportation and services segment
and our interstate transportation and storage segment also contributed to the increase in Adjusted EBITDA primarily due to higher volumes, as well as the
impacts of recently acquired assets and assets recently placed in service. The increases from these segments were partially offset by a decrease in our
midstream segment, primarily driven by the impacts of natural gas and NGL prices, and a decrease in our intrastate transportation and storage segment,
which was impacted by lower pipeline optimization.
Additional information on changes impacting Adjusted EBITDA for the year ended December 31, 2023 compared to the prior year is available below and
in “Segment Operating Results.”
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Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased primarily due to additional depreciation and
amortization from assets recently placed in service and recent acquisitions.
Interest Expense, Net of Interest Capitalized. Interest expense, net of interest capitalized, increased primarily due to higher interest rates on floating rate
debt.
Income Tax Expense. For the year ended December 31, 2023 compared to the same period last year, income tax expense increased due to higher earnings
from the Partnership’s consolidated corporate subsidiaries.
Impairment Losses and Other. For the year ended December 31, 2023, impairment losses and other consisted of impairment losses incurred by USAC
related to its compression equipment.
For the year ended December 31, 2022, impairment losses and other included an $85 million loss on the deconsolidation of Energy Transfer Canada, which
was recorded upon the completion of the sale in August 2022. The amount also included a $300 million impairment related to Energy Transfer Canada’s
assets recorded in March 2022 based on the anticipated proceeds from the expected sale of those assets. The remainder of the impairment losses were from
USAC’s recognition of impairment losses related to its compression equipment.
Gains on Interest Rate Derivatives. Our interest rate derivatives are not designated as hedges for accounting purposes; therefore, changes in fair value are
recorded in earnings each period. Gains on interest rate derivatives resulted from changes in forward interest rates, which caused our forward-starting
swaps to change in value. The magnitude of the gains during the respective periods also reflected changes in the aggregate notional amount of interest rate
swaps outstanding during the respective periods.
Unrealized Gains on Commodity Risk Management Activities. The unrealized gains and losses on our commodity risk management activities include
changes in fair value of commodity derivatives and the hedged inventory included in designated fair value hedging relationships. Information on the
unrealized gains and losses within each segment are included in “Segment Operating Results” below, and additional information on the commodity-related
derivatives, including notional volumes, maturities and fair values, is available in “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”
and in Note 14 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Inventory Valuation Adjustments. Inventory valuation adjustments represent changes in lower of cost or market using the last-in, first-out method on
Sunoco LP’s inventory. These amounts are unrealized valuation adjustments applied to fuel volumes remaining in inventory at the end of the period. For
the year ended December 31, 2023, a decline in fuel prices caused the lower of cost or market reserve requirements to increase by $114 million, which
reduced net income. For the year ended December 31, 2022, an increase in fuel prices caused the lower of cost or market reserve requirements to decrease
by $5 million, which increased net income.
Adjusted EBITDA Related to Unconsolidated Affiliates and Equity in Earnings of Unconsolidated Affiliates. See additional information in “Supplemental
Information on Unconsolidated Affiliates” and “Segment Operation Results” below.
Non-Operating Litigation-Related Loss. Non-operating litigation-related loss recognized for the year ended December 31, 2023 represents the loss
associated with the Williams Litigation, which is discussed in Note 11 to our consolidated financial statements included in “Item 8. Financial Statements
and Supplementary Data.”
Other, net. Other, net primarily includes amortization of regulatory assets and other income and expense amounts.
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Supplemental Information on Unconsolidated Affiliates
The following table presents financial information related to unconsolidated affiliates:
Equity in earnings (losses) of unconsolidated affiliates:
Citrus
MEP
White Cliffs
Explorer
Other
(1)
Total equity in earnings of unconsolidated affiliates
(2)
Adjusted EBITDA related to unconsolidated affiliates :
Citrus
MEP
White Cliffs
Explorer
Other
Total Adjusted EBITDA related to unconsolidated affiliates
Distributions received from unconsolidated affiliates:
Citrus
MEP
White Cliffs
Explorer
Other
Total distributions received from unconsolidated affiliates
Years Ended December 31,
2022
2023
Change
$
$
$
$
$
$
146 $
87
10
37
103
383 $
335 $
121
29
57
149
691 $
135 $
115
25
38
103
416 $
141 $
10
(8)
25
89
257 $
326 $
45
20
41
133
565 $
133 $
27
19
27
88
294 $
5
77
18
12
14
126
9
76
9
16
16
126
2
88
6
11
15
122
(1)
(2)
For the year ended December 31, 2022, equity in earnings (losses) of unconsolidated affiliates included the impact of non-cash impairments recorded
by White Cliffs, which reduced the Partnership’s equity in earnings by $9 million.
These amounts represent our proportionate share of the Adjusted EBITDA of our unconsolidated affiliates and are based on our equity in earnings or
losses of our unconsolidated affiliates adjusted for our proportionate share of the unconsolidated affiliates’ interest, depreciation, depletion,
amortization, non-cash items and taxes.
Segment Operating Results
We evaluate segment performance based on Segment Adjusted EBITDA, which we believe is an important performance measure of the core profitability of
our operations. This measure represents the basis of our internal financial reporting and is one of the performance measures used by senior management in
deciding how to allocate capital resources among business segments.
The following tables identify the components of Segment Adjusted EBITDA, which is calculated as follows:
•
Segment margin, operating expenses and selling, general and administrative expenses. These amounts represent the amounts included in our
consolidated financial statements that are attributable to each segment.
• Unrealized gains or losses on commodity risk management activities and inventory valuation adjustments. These are the unrealized amounts that are
included in cost of products sold to calculate segment margin. These amounts are not included in Segment Adjusted EBITDA; therefore, the unrealized
losses are added back and the unrealized gains are subtracted to calculate the segment measure.
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•
•
Non-cash compensation expense. These amounts represent the total non-cash compensation recorded in operating expenses and selling, general and
administrative expenses related to equity awards. This expense is not included in Segment Adjusted EBITDA and therefore is added back to calculate
the segment measure.
Adjusted EBITDA related to unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to
the unconsolidated affiliate as those excluded from the calculation of Segment Adjusted EBITDA, such as interest, taxes, depreciation, depletion,
amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates, such
exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We do not
control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates.
In the following analysis of segment operating results, a measure of segment margin is reported for segments with sales revenues. Segment margin is a non-
GAAP financial measure and is presented herein to assist in the analysis of segment operating results and particularly to facilitate an understanding of the
impacts that changes in sales revenues have on the segment performance measure of Segment Adjusted EBITDA. Segment margin is similar to the GAAP
measure of gross margin, except that segment margin excludes charges for depreciation, depletion and amortization. Among the GAAP measures reported
by the Partnership, the most directly comparable measure to segment margin is Segment Adjusted EBITDA; a reconciliation of segment margin to Segment
Adjusted EBITDA is included in the following tables for each segment where segment margin is presented.
In addition, for certain segments, the following sections include information on the components of segment margin by sales type, which components are
included in order to provide additional disaggregated information to facilitate the analysis of segment margin and Segment Adjusted EBITDA. For
example, these components include transportation margin, storage margin and other margin. These components of segment margin are calculated consistent
with the calculation of segment margin; therefore, these components also exclude charges for depreciation, depletion and amortization.
Segment Operating Results
Intrastate Transportation and Storage
Natural gas transported (BBtu/d)
Withdrawals from storage natural gas inventory (BBtu)
Revenues
Cost of products sold
Segment margin
Unrealized (gains) losses on commodity risk management activities
Operating expenses, excluding non-cash compensation expense
Selling, general and administrative expenses, excluding non-cash compensation expense
Adjusted EBITDA related to unconsolidated affiliates
Other
Segment Adjusted EBITDA
Years Ended December 31,
2022
2023
Change
14,814
14,840
3,962 $
2,616
1,346
66
(279)
(51)
25
4
1,111 $
14,497
27,283
7,818 $
6,000
1,818
(67)
(334)
(53)
26
6
1,396 $
317
(12,443)
(3,856)
(3,384)
(472)
133
55
2
(1)
(2)
(285)
$
$
Volumes. For the year ended December 31, 2023 compared to the prior year, transported volumes increased primarily due to increased utilization on our
Texas intrastate assets, partially offset by decreased production from our Haynesville assets.
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Segment Margin. The components of our intrastate transportation and storage segment margin were as follows:
Transportation fees
Natural gas sales and other (excluding unrealized gains and losses)
Retained fuel revenues (excluding unrealized gains and losses)
Storage margin, including fees (excluding unrealized gains and losses)
Unrealized gains (losses) on commodity risk management activities
Total segment margin
Years Ended December 31,
2022
2023
Change
$
$
852 $
392
64
104
(66)
1,346 $
828 $
639
186
98
67
1,818 $
24
(247)
(122)
6
(133)
(472)
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our intrastate
transportation and storage segment decreased due to the net impacts of the following:
•
•
•
•
•
a decrease of $247 million in realized natural gas sales and other primarily due to lower pipeline optimization from both physical sales and settled
derivatives; and
a decrease of $122 million in retained fuel revenues related to lower natural gas prices; partially offset by
a decrease of $55 million in operating expenses related to a decrease in cost of fuel consumption from lower natural gas prices;
an increase of $24 million in transportation fees primarily due to new contracts on our Texas system and Haynesville assets; and
an increase of $6 million in storage margin primarily due to higher storage optimization from hedged inventory activity.
Interstate Transportation and Storage
Natural gas transported (BBtu/d)
Natural gas sold (BBtu/d)
Revenues
Cost of products sold
Segment margin
Operating expenses, excluding non-cash compensation, amortization, accretion and other
non-cash expenses
Selling, general and administrative expenses, excluding non-cash compensation,
amortization and accretion expenses
Adjusted EBITDA related to unconsolidated affiliates
Other
Segment Adjusted EBITDA
Years Ended December 31,
2022
2023
Change
16,481
28
2,375 $
6
2,369
14,727
29
2,251 $
25
2,226
(746)
(791)
(115)
496
5
2,009 $
(131)
408
41
1,753 $
$
$
1,754
(1)
124
(19)
143
45
16
88
(36)
256
Volumes. For the year ended December 31, 2023 compared to the prior year, transported volumes increased primarily due to our Gulf Run system going in
service in December 2022 as well as more capacity sold and higher utilization on our Transwestern, Rover and Trunkline systems.
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our interstate
transportation and storage segment increased due to the net impacts of the following:
•
an increase of $143 million in segment margin primarily due to a $141 million increase resulting from our Gulf Run system being placed in service in
December 2022, a $47 million increase in transportation revenue from several of our interstate pipeline systems due to higher contracted volumes and
higher rates, an $18 million increase related to a shipper bankruptcy, a $20 million increase in parking and storage revenue and a $5 million increase in
interruptible utilization. These increases were partially offset by a $58 million decrease due to lower operational gas sales resulting from lower prices,
a $23 million decrease due to lower rates on our Panhandle system resulting from a FERC rate case and an $8 million decrease in liquids revenue due
to lower prices;
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Index to Financial Statements
•
•
•
a decrease of $45 million in operating expenses primarily due to a $65 million decrease from the revaluation of system gas and a $10 million decrease
in ad valorem taxes due to lower assessments on several of our interstate pipelines. These decreases were partially offset by $25 million of incremental
expenses from our Gulf Run system being placed in service in December 2022 and higher maintenance project costs of $4 million;
a decrease of $16 million in selling, general and administrative expenses primarily due to an $11 million decrease in M&A related expenses and a $7
million decrease in professional fees. These decreases were partially offset by $3 million of incremental expenses from our Gulf Run system being
placed in service in December 2022; and
an increase of $88 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to an increase of $76 million from our Midcontinent
Express Pipeline joint venture due to capacity sold at higher rates, a $9 million increase from our Citrus joint venture due to revenues from new
projects and lower operating expenses and an $8 million increase from our Southeast Supply Header joint venture due to increased capacity sold at
higher rates. These increases were partially offset by a $6 million decrease from our Fayetteville Express Pipeline joint venture due to the expiration of
a foundation shipper contract; partially offset by
•
a decrease of $36 million in other Adjusted EBITDA primarily due to the 2022 recognition of certain amounts related to shipper bankruptcies.
Midstream
Gathered volumes (BBtu/d)
NGLs produced (MBbls/d)
Equity NGLs (MBbls/d)
Revenues
Cost of products sold
Segment margin
Operating expenses, excluding non-cash compensation expense
Selling, general and administrative expenses, excluding non-cash compensation expense
Adjusted EBITDA related to unconsolidated affiliates
Other
Segment Adjusted EBITDA
Years Ended December 31,
2022
2023
Change
19,937
880
43
10,406 $
6,503
3,903
(1,204)
(199)
20
5
2,525 $
18,582
800
44
17,101 $
12,682
4,419
(1,087)
(186)
25
39
3,210 $
1,355
80
(1)
(6,695)
(6,179)
(516)
(117)
(13)
(5)
(34)
(685)
$
$
Volumes. For the year ended December 31, 2023 compared to the prior year, gathered volumes and NGL production increased due to newly acquired assets
and higher volumes from existing customers.
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our midstream
segment decreased due to the net impacts of the following:
•
•
•
•
•
•
a decrease of $739 million due to lower natural gas prices of $478 million and lower NGL prices of $261 million;
an increase in operating expenses of $117 million due to a $36 million increase in services and materials, including repairs, volume-driven
consumables and maintenance, compliance and pricing, a $31 million increase in employee costs due to segment reallocations, increased headcount
and wage and benefit costs, a $43 million increase from newly acquired and installed assets, and a $10 million increase in ad valorem taxes, partially
offset by a $4 million decrease in utility costs;
an increase of $13 million in selling, general and administrative expenses primarily due to higher corporate allocations and M&A expenses;
a decrease of $5 million in Adjusted EBITDA related to unconsolidated affiliates primarily due to the sale of the Partnership’s membership interest in
Ranch Westex JV LLC in 2022; and
a decrease of $34 million in other Adjusted EBITDA primarily due to the realization in the previous period of certain amounts related to a shipper
bankruptcy; partially offset by
an increase of $223 million due to newly acquired assets as well as higher volumes across all regions.
111
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Index to Financial Statements
NGL and Refined Products Transportation and Services
NGL transportation volumes (MBbls/d)
Refined products transportation volumes (MBbls/d)
NGL and refined products terminal volumes (MBbls/d)
NGL fractionation volumes (MBbls/d)
Revenues
Cost of products sold
Segment margin
Unrealized (gains) losses on commodity risk management activities
Operating expenses, excluding non-cash compensation expense
Selling, general and administrative expenses, excluding non-cash compensation expense
Adjusted EBITDA related to unconsolidated affiliates
Other
Segment Adjusted EBITDA
Years Ended December 31,
2022
2023
Change
2,116
540
1,430
1,023
21,903 $
17,049
4,854
(38)
(892)
(157)
126
1
3,894 $
1,882
521
1,274
911
25,657 $
21,656
4,001
16
(962)
(127)
97
—
3,025 $
234
19
156
112
(3,754)
(4,607)
853
(54)
70
(30)
29
1
869
$
$
Volumes. For the year ended December 31, 2023 compared to the prior year, NGL transportation volumes increased primarily due to higher volumes from
the Permian region, on our Mariner East pipeline system and on our Gulf Coast export pipelines. The increase in transportation volumes and the
commissioning of our eighth fractionator in August 2023 also led to higher fractionated volumes at our Mont Belvieu, Texas fractionation facility.
Segment Margin. The components of our NGL and refined products transportation and services segment margin were as follows:
Fractionators and refinery services margin
Transportation margin
Storage margin
Terminal services margin
Marketing margin
Unrealized gains (losses) on commodity risk management activities
Total segment margin
Years Ended December 31,
2022
2023
Change
$
$
888 $
2,399
319
892
318
38
4,854 $
850 $
2,126
284
699
58
(16)
4,001 $
38
273
35
193
260
54
853
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our NGL and refined
products transportation and services segment increased due to the net impacts of the following:
•
•
•
an increase of $273 million in transportation margin primarily due to a $136 million increase resulting from higher throughput and contractual rate
escalations on our Texas y-grade pipeline system, a $95 million increase resulting from higher throughput and contractual rate escalations on our
Mariner East pipeline system, a $41 million increase from higher export volumes feeding into our Nederland Terminal, a $27 million increase from
higher throughput and contractual rate escalations on our refined product pipelines, a $12 million increase from the timing of third-party deficiency
payments on our Northeast region pipelines and a $7 million increase from higher throughput on our Mariner West pipeline. These increases were
partially offset by intrasegment charges of $29 million and $17 million which were fully offset within our marketing and fractionation margins,
respectively;
an increase of $260 million in marketing margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to
higher gains during 2023 from the optimization of hedged NGL and refined product inventories, as well as intrasegment margin of $29 million which
was fully offset within our transportation margin;
an increase of $193 million in terminal services margin primarily due to a $120 million increase from our Marcus Hook Terminal due to contractual
rate escalations and higher throughput, a $65 million increase from higher export volumes
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Index to Financial Statements
loaded at our Nederland Terminal, a $4 million increase due to higher throughput from our refined product marketing terminals and a $3 million
increase from tank leases at our Eagle Point Terminal;
a decrease of $70 million in operating expenses primarily due to an $87 million decrease in gas and power utility costs, partially offset by a $16 million
increase in employee costs;
an increase of $38 million in fractionators and refinery services margin primarily due to a $29 million increase resulting from higher volumes and $17
million in intrasegment margin which was fully offset within our transportation margin. These increases were partially offset by an $8 million decrease
from our refinery services business;
an increase of $35 million in storage margin associated with increased NGL export volumes; and
an increase of $29 million in Adjusted EBITDA related to unconsolidated affiliates due to higher volumes on certain joint venture pipelines; partially
offset by
an increase of $30 million in selling, general and administrative expenses primarily due to a $13 million increase resulting from a one-time charge
related to regulatory expenses, a $9 million increase in overhead expenses and a $6 million increase in insurance costs.
•
•
•
•
•
Crude Oil Transportation and Services
Crude oil transportation volumes (MBbls/d)
Crude oil terminals volumes (MBbls/d)
Revenue
Cost of products sold
Segment margin
Unrealized (gains) losses on commodity risk management activities
Operating expenses, excluding non-cash compensation expense
Selling, general and administrative expenses, excluding non-cash compensation expense
Adjusted EBITDA related to unconsolidated affiliates
Other
Segment Adjusted EBITDA
Years Ended December 31,
2022
2023
Change
5,282
3,377
26,536 $
23,071
3,465
13
(699)
(120)
19
3
2,681 $
4,345
2,964
25,982 $
22,917
3,065
(14)
(645)
(224)
4
1
2,187 $
$
$
937
413
554
154
400
27
(54)
104
15
2
494
Volumes. For the year ended December 31, 2023 compared to the prior year, crude oil transportation volumes were higher on our Texas pipeline system due
to higher Permian crude oil production, higher gathered volumes and contributions from assets acquired in 2023. Bakken Pipeline volumes were also
higher. Volumes on our Bayou Bridge Pipeline were higher due to continuing strong Gulf Coast refinery demand. Midcontinent systems were higher,
driven by contributions from assets acquired in 2023. We also realized higher Bakken gathering volumes. Crude terminal volumes were higher due to
growth in Permian and Bakken volumes, stronger Gulf Coast refinery utilization and contributions from assets acquired in 2023.
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to our crude oil
transportation and services segment increased due to the net impacts of the following:
•
•
•
an increase of $427 million in segment margin (excluding unrealized gains and losses on commodity risk management activities) primarily due to a
$275 million increase from recently acquired assets, a $157 million increase from higher volumes on our Bakken Pipeline, a $71 million increase from
higher volumes on our Texas crude pipeline system, a $31 million increase from our Nederland and Houston crude terminals due to higher throughput
and exports and a $17 million increase from our Midcontinent gathering systems, partially offset by a $135 million decrease from our crude oil
acquisition and marketing business due primarily to less favorable pricing and higher affiliate fees from higher volumes transported;
a decrease of $104 million in selling, general and administrative expenses primarily due to a charge related to a legal matter in the prior period; and
an increase of $15 million in Adjusted EBITDA related to unconsolidated affiliates due to assets acquired and higher volumes on our White Cliffs
crude pipeline; partially offset by
113
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Index to Financial Statements
•
an increase of $54 million in operating expenses primarily due to a $66 million increase from recently acquired assets, a $13 million increase in
volume-driven expenses and an $8 million increase in employee-related expenses, partially offset by a $4 million decrease in measurement expenses, a
$5 million decrease in ad valorem taxes and a $20 million decrease in maintenance project expenses.
Investment in Sunoco LP
Revenues
Cost of products sold
Segment margin
Unrealized (gains) losses on commodity risk management activities
Operating expenses, excluding non-cash compensation expense
Selling, general and administrative, excluding non-cash compensation expense
Adjusted EBITDA related to unconsolidated affiliates
Inventory valuation adjustments
Other, net
Segment Adjusted EBITDA
The Investment in Sunoco LP segment reflects the consolidated results of Sunoco LP.
Years Ended December 31,
2022
2023
Change
$
$
23,068 $
21,703
1,365
(21)
(420)
(113)
10
114
29
964 $
25,729 $
24,350
1,379
21
(396)
(111)
10
(5)
21
919 $
(2,661)
(2,647)
(14)
(42)
(24)
(2)
—
119
8
45
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA related to the Investment in
Sunoco LP segment decreased due to the net impacts of the following:
•
•
•
an increase in the gross profit on motor fuel sales of $34 million primarily due to an 8% increase in gallons sold; and
an increase in non-motor fuel sales and lease profit of $37 million primarily due to increased throughput and storage margin from the Gladieux and
Zenith acquisitions and increased rental income; partially offset by
an increase in operating costs of $26 million, including other operating expense, general and administrative expense and lease expense. The increase
was primarily due to higher costs as a result of the recent acquisitions of refined product terminals and the transmix processing and terminal facility.
Investment in USAC
Revenues
Cost of products sold
Segment margin
Operating expenses, excluding non-cash compensation expense
Selling, general and administrative, excluding non-cash compensation expense
Other, net
Segment Adjusted EBITDA
The investment in USAC segment reflects the consolidated results of USAC.
Years Ended December 31,
2022
2023
Change
$
$
846 $
137
709
(147)
(51)
1
512 $
705 $
111
594
(123)
(45)
—
426 $
141
26
115
(24)
(6)
1
86
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to last year, Segment Adjusted EBITDA related to our investment in USAC
segment increased due to the net impacts of the following:
•
an increase of $115 million in segment margin primarily due to higher revenue-generating horsepower as a result of increased demand for compression
services, higher market-based rates on newly deployed and redeployed compression units and higher average rates on existing customer contracts;
partially offset by
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Index to Financial Statements
•
an increase of $24 million in operating expenses primarily due to higher employee costs associated with increased revenue-generating horsepower as
well as higher parts and service costs.
All Other
Revenue
Cost of products sold
Segment margin
Unrealized (gains) losses on commodity risk management activities
Operating expenses, excluding non-cash compensation expense
Selling, general and administrative expenses, excluding non-cash compensation expense
Adjusted EBITDA related to unconsolidated affiliates
Other and eliminations
Segment Adjusted EBITDA
Amounts reflected in our all other segment primarily include:
•
•
•
•
our natural gas marketing operations;
our wholly owned natural gas compression operations;
our investment in coal handling facilities; and
our Canadian operations, until those assets were divested in August 2022.
Years Ended December 31,
2022
2023
Change
1,798 $
1,740
58
(22)
(40)
(85)
4
87
2 $
3,574 $
3,328
246
2
(80)
(60)
4
65
177 $
(1,776)
(1,588)
(188)
(24)
40
(25)
—
22
(175)
$
$
Segment Adjusted EBITDA. For the year ended December 31, 2023 compared to the prior year, Segment Adjusted EBITDA decreased primarily due to the
net impacts of the following:
•
•
•
•
•
•
•
a decrease of $35 million due to higher M&A expenses;
a decrease of $80 million due to the sale of Energy Transfer Canada in 2022;
a decrease of $25 million from our dual drive compression business due to lower gas prices and increased electricity cost;
a decrease of $21 million due to less favorable power trading market conditions;
an increase of $8 million in ad valorem taxes due to tax credits utilized in 2022; and
a decrease of $9 million in storage and trading gains; partially offset by
an increase of $27 million due to increased sales in our compressor packaging business.
LIQUIDITY AND CAPITAL RESOURCES
Our ability to satisfy our obligations and pay distributions to Unitholders will depend on our future performance, which will be subject to prevailing
economic, financial, business, weather conditions and other factors, many of which are beyond management’s control. The significant trends and
uncertainties that we currently believe could significantly impact our liquidity and cash flows going forward are discussed in “Trends and Outlook” above.
We believe that we have sufficient liquidity and sources of funding to meet our cash requirements over the near term and for the longer term. We expect to
satisfy our working capital needs through cash generated by our operations. As of December 31, 2023, we had cash and cash equivalents of $161 million
and availability under our revolving credit facility of $3.56 billion.
The Partnership’s material contractual obligations include long-term debt service, payments under operating leases and purchase commitments. The
Partnership’s obligations under its long-term debt agreements are described below under “Description of Indebtedness,” and information on the maturities
and interest rates related to the Partnership’s long-term debt is available in Note 6 to our consolidated financial statements included in “Item 8. Financial
Statements and Supplementary Data.” In addition, information on the Partnership’s obligations under its lease arrangements is included in Note 13 to our
consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
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We define a purchase commitment as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies
all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of
the transactions. We have long and short-term product purchase obligations for commodities with third-party suppliers. These purchase obligations are
entered into at either variable or fixed prices. The purchase prices that we are obligated to pay under variable price contracts approximate market prices at
the time we take delivery of the volumes. The purchase prices that we are obligated to pay under fixed price contracts are established at the inception of the
contract. We have material purchase commitments for crude oil; as of December 31, 2023, those purchase commitments totaled an estimated $65.27 billion
(of which $21.80 billion would be due in 2024) based on either the current market price for variable price contracts or the contracted price for fixed price
contracts.
We currently expect capital expenditures in 2024 to be within the following ranges (including capitalized interest and overhead, but excluding capital
expenditures related to our investments in Sunoco LP and USAC):
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
All other (including eliminations)
(1)
(1)
Total capital expenditures
Growth
Maintenance
Low
High
Low
High
$
$
115 $
45
590
1,400
195
55
2,400 $
125 $
55
645
1,500
215
60
2,600 $
50 $
190
220
135
175
65
835 $
55
195
225
140
180
70
865
(1)
Includes capital expenditures related to the Partnership’s proportionate ownership of the Bakken, Rover and Bayou Bridge pipeline joint ventures as
well as the Orbit Gulf Coast NGL Exports joint venture.
The assets used in our natural gas and liquids operations, including pipelines, gathering systems and related facilities, are generally long-lived assets and do
not require significant maintenance capital expenditures. Accordingly, we do not have any significant financial commitments for maintenance capital
expenditures in our businesses. From time to time, we experience increases in pipe costs due to a number of reasons, including but not limited to, delays
from steel mills, limited selection of mills capable of producing large diameter pipe timely, higher steel prices and other factors beyond our control.
However, we include these factors in our anticipated growth capital expenditures for each year.
We generally fund maintenance capital expenditures and distributions with cash flows from operating activities. We generally expect to funds growth
capital expenditures with proceeds of borrowings under our credit facilities, along with cash from operations.
Sunoco LP expects to invest at least $200 million in growth capital expenditures and approximately $70 million in maintenance capital expenditures in
2024.
USAC currently plans to spend approximately $32 million in maintenance capital expenditures and currently has budgeted between $115 million and
$125 million in expansion capital expenditures in 2024.
Cash Flows
Our cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price of our
products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational
risks, the successful integration of our acquisitions and other factors.
Operating Activities
Changes in cash flows from operating activities between periods primarily result from changes in earnings (as discussed in “Results of Operations” above),
excluding the impacts of non-cash items and changes in operating assets and liabilities. Non-cash items include recurring non-cash expenses, such as
depreciation, depletion and amortization expense and non-cash compensation expense. The increase in depreciation, depletion and amortization expense
during the periods presented primarily resulted from construction and acquisitions of assets, while changes in non-cash compensation expense resulted
from changes in the number of units granted and changes in the grant date fair value for such grants. Cash flows from operating activities also differ from
earnings as a result of non-cash charges that may not be recurring such as impairment charges and allowance for equity funds used during construction. The
allowance for equity funds used during construction increases in periods when
116
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Index to Financial Statements
Energy Transfer has a significant amount of interstate pipeline construction in progress. Changes in operating assets and liabilities between periods result
from factors such as the changes in the value of derivative assets and liabilities, timing of accounts receivable collection, payments on accounts payable, the
timing of purchases and sales of inventories, and the timing of advances and deposits received from customers.
Following is a summary of operating activities by period:
Year Ended December 31, 2023
Cash provided by operating activities in 2023 was $9.56 billion and net income was $5.29 billion. The difference between net income and cash provided by
operating activities in 2023 primarily consisted of non-cash items totaling $4.43 billion offset by net changes in operating assets and liabilities of
$451 million. The non-cash activity in 2023 consisted primarily of depreciation, depletion and amortization of $4.39 billion, impairment losses of
$12 million, non-cash compensation expense of $130 million, equity in earnings of unconsolidated affiliates of $383 million, unfavorable inventory
valuation adjustments of $114 million, gains on extinguishments of debt of $2 million, and deferred income taxes of $203 million. The Partnership also
received distributions of $353 million from unconsolidated affiliates.
Year Ended December 31, 2022
Cash provided by operating activities in 2022 was $9.05 billion and net income was $5.87 billion. The difference between net income and cash provided by
operating activities in 2022 primarily consisted of non-cash items totaling $4.53 billion offset by net changes in operating assets and liabilities of
$1.50 billion. The non-cash activity in 2022 consisted primarily of depreciation, depletion and amortization of $4.16 billion, impairment losses of
$386 million, non-cash compensation expense of $115 million, equity in earnings of unconsolidated affiliates of $257 million, favorable inventory
valuation adjustments of $5 million, and deferred income taxes of $187 million. The Partnership also received distributions of $232 million from
unconsolidated affiliates.
Investing Activities
Cash flows from investing activities primarily consist of cash amounts paid for acquisitions, capital expenditures, cash distributions from our joint ventures,
and cash proceeds from sales or contributions of assets or businesses. Changes in capital expenditures between periods primarily result from increases or
decreases in our growth capital expenditures to fund our construction and expansion projects.
Following is a summary of investing activities by period:
Year Ended December 31, 2023
Cash used in investing activities in 2023 was $4.33 billion. Total capital expenditures (excluding the allowance for equity funds used during construction
and net of contributions in aid of construction costs) were $3.09 billion. Additional detail related to our capital expenditures is provided in the following
table. We received $38 million of cash proceeds from the sale of assets. The Partnership also received distributions of $63 million from unconsolidated
affiliates. In 2023, we paid $288 million in cash for the Crestwood acquisition, we paid $930 million in cash for the Lotus Midstream acquisition and
Sunoco LP paid $111 million in cash for the acquisition of 16 refined product terminals from Zenith Energy.
Year Ended December 31, 2022
Cash used in investing activities in 2022 was $4.02 billion. Total capital expenditures (excluding the allowance for equity funds used during construction
and net of contributions in aid of construction costs) were $3.33 billion. Additional detail related to our capital expenditures is provided in the following
table. We received $78 million of cash proceeds from the sale of assets. The Partnership also received distributions of $62 million from unconsolidated
affiliates. In 2022, we paid $1.14 billion in cash for acquisitions, net of cash received. In 2022, we received $302 million in cash from the sale of our
interest in Energy Transfer Canada.
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Index to Financial Statements
The following is a summary of the Partnership’s capital expenditures (including only our proportionate share of the Bakken, Rover, Bayou Bridge and
Orbit Gulf Coast NGL Exports joint ventures, net of contributions in aid of construction costs) by period:
Year Ended December 31, 2023:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
Investment in Sunoco LP
Investment in USAC
All other (including eliminations)
Total capital expenditures
Year Ended December 31, 2022:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
Investment in Sunoco LP
Investment in USAC
All other (including eliminations)
Total capital expenditures
Financing Activities
Capital Expenditures Recorded During Period
Growth
Maintenance
Total
$
$
$
$
54 $
219
586
551
143
145
275
38
2,011 $
132 $
456
812
376
120
132
145
32
2,205 $
39 $
164
246
128
123
70
25
62
857 $
47 $
188
192
131
126
54
24
59
821 $
93
383
832
679
266
215
300
100
2,868
179
644
1,004
507
246
186
169
91
3,026
Changes in cash flows from financing activities between periods primarily result from changes in the levels of borrowings and equity issuances, which are
primarily used to fund our acquisitions and growth capital expenditures. Distributions to partners increased between the periods as a result of increases in
the number of common units outstanding or increases in the distribution rate.
Following is a summary of financing activities by period:
Year Ended December 31, 2023
Cash used in financing activities was $5.33 billion in 2023. In 2023, we had a net increase in our debt level of $714 million. During 2023, we paid
distributions of $4.25 billion to our partners, we paid distributions of $1.69 billion to noncontrolling interests, and we paid distributions of $59 million to
our redeemable noncontrolling interests. In addition, we received capital contributions of $3 million in cash from noncontrolling interests. During 2023, we
incurred debt issuance costs of $45 million.
Year Ended December 31, 2022
Cash used in financing activities was $5.11 billion in 2022. In 2022, we had a net decrease in our debt level of $843 million. During 2022, we paid
distributions of $3.05 billion to our partners, we paid distributions of $1.55 billion to noncontrolling interests, and we paid distributions of $49 million to
our redeemable noncontrolling interests. In addition, we received capital contributions of $405 million in cash from noncontrolling interests. During 2022,
we incurred debt issuance costs of $27 million.
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Description of Indebtedness
Our outstanding consolidated indebtedness was as follows:
Energy Transfer Indebtedness:
Notes and Debentures
Five-Year Credit Facility
(1)(2)
(2)
Subsidiary Indebtedness:
(1)
Transwestern Senior Notes
Bakken Project Senior Notes
Sunoco LP Senior Notes and lease-related obligations
USAC Senior Notes
HFOTCO Tax Exempt Notes
(2)
Sunoco LP Credit Facility
USAC Credit Facility
(2)
(2)
Other long-term debt
Net unamortized premiums, discounts and fair value adjustments
Deferred debt issuance costs
Total debt
Less: current maturities of long-term debt
(3)
Long-term debt, less current maturities
December 31,
2023
2022
$
$
43,016 $
1,412
250
1,850
3,194
1,475
—
411
872
18
127
(237)
52,388
1,008
51,380 $
39,468
793
250
1,850
2,694
1,475
225
900
646
3
183
(225)
48,262
2
48,260
(1)
(2)
(3)
As of December 31, 2023, these balances included a total of $3.67 billion aggregate principal amount of senior notes due on or before December 31,
2024 which were classified as long-term as management has the intent and ability to refinance the borrowings on a long-term basis.
See additional information below under “Recent Transactions.”
As of December 31, 2023, current maturities of long-term debt reflected on the Partnership’s consolidated balance sheet included $1.00 billion of
senior notes issued by the Bakken Pipeline entities which mature in April 2024. The Partnership’s proportional ownership in the Bakken Pipeline
entities is 36.4%.
The terms of our consolidated indebtedness and that of our subsidiaries are described in more detail below and in Note 6 to our consolidated financial
statements included in “Item 8. Financial Statements and Supplementary Data.”
Recent Transactions
In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% Senior Notes due 2034, $1.75 billion aggregate principal amount
of 5.95% Senior Notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate Junior Subordinated Notes due 2054. The
Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility (defined below), to redeem
its outstanding Series C Preferred Units and Series D Preferred Units and for general partnership purposes. The Partnership also intends to use the proceeds
to redeem its Series E Preferred Units in May 2024.
In November 2023, concurrent with the closing of the Crestwood acquisition, the Partnership assumed $2.85 billion aggregate principal amount of
Crestwood senior notes and terminated its revolving credit facility, which included the repayment of $613 million in outstanding borrowings.
In November 2023, the Partnership redeemed $600 million aggregate principal amount of its 4.50% Senior Notes due November 2023 using proceeds from
the senior notes offering discussed in the following paragraph.
In October 2023, the Partnership issued $1.00 billion aggregate principal amount of 6.05% Senior Notes due 2026, $500 million aggregate principal
amount of 6.10% Senior Notes due 2028, $1.00 billion aggregate principal amount of 6.40% Senior Notes due 2030 and $1.50 billion aggregate principal
amount of 6.55% Senior Notes due 2033. The Partnership used the net proceeds
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to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility and for general partnership purposes.
In September 2023, the Partnership redeemed $500 million aggregate principal amount of its 4.20% Senior Notes due September 2023 using proceeds from
its Five-Year Credit Facility.
In May 2023, the Partnership refinanced all of the $225 million outstanding principal amount of HFOTCO tax-exempt bonds with new 10-year tax-exempt
bonds. The new bonds, which were issued through the Harris County Industrial Development Corporation and are obligations of Energy Transfer, accrue
interest at a fixed rate of 4.05% and are mandatorily redeemable in 2033. Upon redemption, these tax-exempt bonds may be remarketed on different terms
through final maturity of November 1, 2050.
In the first quarter of 2023, the Partnership redeemed $350 million aggregate principal amount of its 3.45% Senior Notes due January 2023, $800 million
aggregate principal amount of its 3.60% Senior Notes due February 2023 and $1.00 billion aggregate principal amount of its 4.25% Senior Notes due
March 2023 using proceeds from its Five-Year Credit Facility.
In September 2023, Sunoco LP completed a private offering of $500 million aggregate principal amount of 7.00% senior notes due 2028. Sunoco LP used
the proceeds from the private offering to repay a portion of its outstanding borrowings under their revolving credit facility.
Credit Facilities and Commercial Paper
Five-Year Credit Facility
The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion and matures on April 11, 2027. The Five-Year Credit
Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.
As of December 31, 2023, the Five-Year Credit Facility had $1.41 billion of outstanding borrowings, $1.37 billion of which consisted of commercial paper.
The amount available for future borrowings was $3.56 billion, after accounting for outstanding letters of credit in the amount of $29 million. The weighted
average interest rate on the total amount outstanding as of December 31, 2023 was 5.87%.
Sunoco LP Credit Facility
As of December 31, 2023, the Sunoco LP Credit Facility had $411 million of outstanding borrowings and $5 million in standby letters of credit and
matures in April 2027. The amount available for future borrowings was $1.08 billion at December 31, 2023. The weighted average interest rate on the total
amount outstanding as of December 31, 2023 was 7.54%.
USAC Credit Facility
As of December 31, 2023, USAC had $872 million of outstanding borrowings and no outstanding letters of credit under the credit agreement. As of
December 31, 2023, USAC had $728 million of remaining unused availability of which, due to restrictions related to compliance with the applicable
financial covenants, $529 million was available to be drawn. The weighted average interest rate on the total amount outstanding as of December 31, 2023
was 7.98%.
Covenants Related to Our Credit Agreements
The agreements relating to the Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies,
which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The Five-Year Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’
ability to, among other things:
•
•
•
•
incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
• make certain investments;
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• make Distributions (as defined in the Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during any
Event of Default (as defined in the Five-Year Credit Facility);
•
•
•
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
engage in transactions with affiliates; and
enter into restrictive agreements.
The applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our
senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the Five-Year Credit Facility ranges from
1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the Five-
Year Credit Facility ranges from 0.125% to 0.300%.
The Five-Year Credit Facility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation and
conduct of our business. The Five-Year Credit Facility also limits us, on a rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to
Consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.00 to 1.00, which can generally be increased to 5.50 to 1.00 during a
Specified Acquisition Period. Our Leverage Ratio was 3.31 to 1.00 at December 31, 2023, as calculated in accordance with the credit agreement.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to
scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay distributions
to Unitholders.
Covenants Related to Transwestern
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the
sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control event
of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage ratio.
In connection with Sunoco LP’s acquisition of NuStar, Sunoco LP expects to assume NuStar’s debt and issue additional debt, aggregating approximately
$4.2 billion, subsequent to which it expects to remain in compliance with all existing financial covenants.
Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:
•
grant liens;
• make certain loans or investments;
•
•
incur additional indebtedness or guarantee other indebtedness;
enter into transactions with affiliates;
• merge or consolidate;
•
sell our assets; and
• make certain acquisitions.
The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:
•
•
•
a minimum EBITDA to interest coverage ratio;
a ratio of total secured indebtedness to EBITDA within a specified range; and
a maximum funded debt to EBITDA ratio.
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Compliance with our Covenants
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31,
2023.
Cash Distributions
Cash Distributions Paid by Energy Transfer
Under its Partnership Agreement, Energy Transfer will distribute all of its Available Cash, as defined in the Partnership Agreement, within 50 days
following the end of each fiscal quarter. Available Cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the
amount of cash reserves that are necessary or appropriate in the reasonable discretion of our general partner that is necessary or appropriate to provide for
future cash requirements.
Energy Transfer Common Unit Distributions
Distributions declared and paid with respect to Energy Transfer common units were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2020
March 31, 2021
June 30, 2021
September 30, 2021
December 31, 2021
March 31, 2022
June 30, 2022
September 30, 2022
December 31, 2022
March 31, 2023
June 30, 2023
September 30, 2023
December 31, 2023
$
February 8, 2021
May 11, 2021
August 6, 2021
November 5, 2021
February 8, 2022
May 9, 2022
August 8, 2022
November 4, 2022
February 7, 2023
May 8, 2023
August 14, 2023
October 30, 2023
February 7, 2024
February 19, 2021
May 19, 2021
August 19, 2021
November 19, 2021
February 18, 2022
May 19, 2022
August 19, 2022
November 21, 2022
February 21, 2023
May 22, 2023
August 21, 2023
November 20, 2023
February 20, 2024
0.1525
0.1525
0.1525
0.1525
0.1750
0.2000
0.2300
0.2650
0.3050
0.3075
0.3100
0.3125
0.3150
The total amounts of distributions declared and paid during the periods presented (all from Available Cash from Energy Transfer’s operating surplus and
are shown in the period to which they relate) are as follows:
Limited Partners
General Partner interest
Total Energy Transfer distributions
122
Years Ended December 31,
2022
2023
$
$
3,984 $
3
3,987 $
3,089
3
3,092
Table of Contents
Index to Financial Statements
Energy Transfer Preferred Unit Distributions
Distributions on Energy Transfer’s preferred units declared and/or paid by Energy Transfer were as follows:
Period Ended
Record Date
Payment Date
Series A
(1)
Series B
(1)
May 3, 2021
May 17, 2021
$—
$—
Series C
$0.4609
Series D
$0.4766
Series E
$0.4750
Series F
(1)
Series G
(1)
Series H
(1)
$33.75
$35.63
August 2, 2021 August 16,
31.25
33.125
0.4609
0.4766
0.4750
—
—
November 1,
2021
February 1,
2022
May 2, 2022
2021
November 15,
2021
February 15,
2022
May 16, 2022
—
—
0.4609
0.4766
0.4750
33.75
35.63
27.08
*
31.25
33.125
0.4609
0.4766
0.4750
—
—
—
—
—
0.4609
0.4766
0.4750
33.75
35.63
32.50
August 1, 2022 August 15,
31.25
33.125
0.4609
0.4766
0.4750
—
—
—
$—
—
March 31,
2021
June 30, 2021
September 30,
2021
December 31,
2021
March 31,
2022
June 30, 2022
September 30,
2022
December 31,
2022
March 31,
2023
June 30, 2023
November 1,
2022
February 1,
2023
May 1, 2023
2022
November 15,
2022
February 15,
2023
May 15, 2023
August 1, 2023 August 15,
September 30,
2023
December 31,
2023
November 1,
2023
February 1,
2024
2023
November 15,
2023
February 15,
2024
*
Represents prorated initial distribution.
—
31.25
21.98
23.89
24.67
24.71
—
0.4609
0.4766
0.4750
33.75
35.63
32.50
33.125
0.4609
0.4766
0.4750
—
—
—
—
0.4609
0.4766
0.4750
33.75
35.63
32.50
33.125
0.6294
0.4766
0.4750
—
—
—
—
0.6489
0.6622
0.4750
33.75
35.63
32.50
33.125
0.6075
0.6199
0.4750
—
—
—
0.2111
Series I
$—
—
—
—
—
—
—
—
—
—
—
(1)
Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series A
preferred units began to be paid quarterly on February 15, 2023, and distributions on the Series B preferred units will begin to be paid quarterly on
February 15, 2028.
Sunoco LP Cash Distributions
Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Sunoco LP’s IDRs. As of December 31, 2023, Sunoco LP had
approximately 84.4 million common units outstanding.
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder
of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal
percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus
which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The
percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution
amounts that are less than the minimum quarterly distribution.
Minimum Quarterly Distribution
First Target Distribution
Second Target Distribution
Third Target Distribution
Thereafter
Marginal Percentage Interest in
Distributions
Common
Unitholders
100%
100%
85%
75%
50%
Holder of IDRs
—%
—%
15%
25%
50%
Total Quarterly Distribution Target Amount
$0.4375
$0.4375 to $0.503125
$0.503125 to $0.546875
$0.546875 to $0.656250
Above $0.656250
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Index to Financial Statements
Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2020
March 31, 2021
June 30, 2021
September 30, 2021
December 31, 2021
March 31, 2022
June 30, 2022
September 30, 2022
December 31, 2022
March 31, 2023
June 30, 2023
September 30, 2023
December 31, 2023
February 8, 2021
May 11, 2021
August 6, 2021
November 5, 2021
February 8, 2022
May 9, 2022
August 8, 2022
November 4, 2022
February 7, 2023
May 8, 2023
August 14, 2023
October 30, 2023
February 7, 2024
$
February 19, 2021
May 19, 2021
August 19, 2021
November 19, 2021
February 18, 2022
May 19, 2022
August 19, 2022
November 18, 2022
February 21, 2023
May 22, 2023
August 21, 2023
November 20, 2023
February 20, 2024
The total amount of distributions to the Partnership from Sunoco LP for the periods presented below is as follows:
0.8255
0.8255
0.8255
0.8255
0.8255
0.8255
0.8255
0.8255
0.8255
0.8420
0.8420
0.8420
0.8420
Distributions from Sunoco LP
Limited Partner interests
General Partner interest and IDRs
Total distributions from Sunoco LP
USAC Cash Distributions
Years Ended December 31,
2022
2023
$
$
96 $
77
173 $
94
72
166
Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2023, USAC had approximately 101.0 million common units
outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.
Distributions on USAC’s units declared and/or paid by USAC were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2020
March 31, 2021
June 30, 2021
September 30, 2021
December 31, 2021
March 31, 2022
June 30, 2022
September 30, 2022
December 31, 2022
March 31, 2023
June 30, 2023
September 30, 2023
December 31, 2023
January 25, 2021
April 26, 2021
July 26, 2021
October 25, 2021
January 24, 2022
April 25, 2022
July 25, 2022
October 24, 2022
January 23, 2023
April 24, 2023
July 24, 2023
October 23, 2023
January 22, 2024
$
February 5, 2021
May 7, 2021
August 6, 2021
November 5, 2021
February 4, 2022
May 6, 2022
August 5, 2022
November 4, 2022
February 3, 2023
May 5, 2023
August 4, 2023
November 3, 2023
February 2, 2024
124
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
Table of Contents
Index to Financial Statements
The total amount of distributions to the Partnership from USAC for the periods presented below is as follows:
Distributions from USAC
Limited Partner interests
Total distributions from USAC
Critical Accounting Estimates
Years Ended December 31,
2022
2023
$
$
97 $
97 $
97
97
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the
accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and
interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to
properly comply with all applicable rules, and we believe the proper implementation and consistent application of the accounting rules are critical. Our
critical accounting policies are discussed below. For further details on our accounting policies see Note 2 to our consolidated financial statements included
in “Item 8. Financial Statements and Supplementary Data.”
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions
at the end of the month following the month of delivery. Consequently, the most current month’s financial results are estimated using volume estimates and
market prices for our intrastate transportation and storage segment, our midstream segment, and our NGL and refined products transportation and services
segment. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes
that the operating results estimated for the year ended December 31, 2023 represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged,
the fair value of derivative instruments, useful lives for depreciation, depletion and amortization, purchase accounting allocations and subsequent
realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting
from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Fair Value Estimates in Business Combination Accounting and Impairment of Long-Lived Assets, Goodwill, Intangible Assets and Investments in
Unconsolidated Affiliates. Business combination accounting and quantitative impairment testing are required from time to time due to the occurrence of
events, changes in circumstances, or annual testing requirements. For business combinations, assets and liabilities are required to be recorded at estimated
fair value in connection with the initial recognition of the transaction. For impairment testing, long-lived assets are required to be tested for recoverability
whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Goodwill and intangibles with
indefinite lives must be tested for impairment annually or more frequently if events or changes in circumstances indicate that the related asset might be
impaired. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is
other than temporary. An impairment loss should be recognized only if the carrying amount of the asset/goodwill is not recoverable and exceeds its fair
value. Calculating the fair value of assets or reporting units in connection with business combination accounting or impairment testing requires
management to make several estimates, assumptions and judgements, and in some circumstances management may also utilize third-party specialists to
assist and advise on those calculations.
In order to allocate the purchase price in a business combination or to test for recoverability when performing a quantitative impairment test, we must make
estimates of projected cash flows related to the asset, which include, but are not limited to, assumptions about the use or disposition of the asset, estimated
remaining life of the asset, and future expenditures necessary to maintain the asset’s existing service potential. In order to determine fair value, we make
certain estimates and assumptions, including, among other things, changes in general economic conditions in regions in which our markets are located, the
availability and prices of commodities, our ability to negotiate favorable sales agreements, the risks that exploration and production activities will not occur
or be successful, our dependence on certain significant customers and producers, and competition from other companies, including major energy producers.
While we believe we have made reasonable assumptions to calculate the fair value, if future results are not consistent with our estimates, we could be
exposed to future impairment losses that could be material to our results of operations.
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The Partnership determines the fair value of its assets and/or reporting units using the discounted cash flow method, the guideline company method, the
reproduction and replacement methods, or a weighted combination of these methods. Determining the fair value of a reporting unit requires judgment and
the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs
of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our business combination accounting
and impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially
different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the
Partnership determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to
present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived
from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management.
Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the
guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of
comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations
using a multi-year average. In addition, the Partnership estimates a reasonable control premium, when appropriate, representing the incremental value that
accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. Under the reproduction and replacement
methods, the Partnership determines the fair value of assets based on the estimated installation, engineering, and set-up costs related to the asset; these
methods require the use of trend factors, such as inflation indices.
One key assumption in these fair value calculations is management’s estimate of future cash flows and EBITDA. In accounting for a business combination,
these estimates are generally based on the forecasts that were used to analyze the deal economics. For impairment testing, these estimates are based on the
annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the
annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected
to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised
expectations. The estimates of future cash flows and EBITDA are subjective in nature and are subject to impacts from the business risks described in “Item
1A. Risk Factors.” Therefore, the actual results could differ significantly from the amounts used for business combination accounting and impairment
testing, and significant changes in fair value estimates could occur in a given period. Such changes in fair value estimates could result in changes to the fair
value estimates used in business combination accounting, which could significantly impact results of operations in a period subsequent to the business
combination, depending on multiple factors, including the timing of such changes. In the case of impairment testing, such changes could result in additional
impairments in future periods; therefore, the actual results could differ significantly from the amounts used for goodwill impairment testing, and significant
changes in fair value estimates could occur in a given period, resulting in additional impairments.
In addition, we may change our method of impairment testing, including changing the weight assigned to different valuation models. Such changes could
be driven by various factors, including the level of precision or availability of data for our assumptions. Any changes in the method of testing could also
result in an impairment or impact the magnitude of an impairment.
During the years ended December 31, 2023, 2022 and 2021, the Partnership recorded total assets of $9.71 billion, $1.38 billion and $8.58 billion,
respectively, in connection with business combinations.
During the years ended December 31, 2023, 2022 and 2021, the Partnership recorded impairments totaling $12 million, $386 million and $21 million,
respectively. Additional information on the impairments recorded during these periods is available in Note 2 to our consolidated financial statements
included in “Item 8. Financial Statements and Supplementary Data.”
Management does not believe that any of the Partnership’s goodwill balances, long-lived assets or investments in unconsolidated affiliates is currently at
significant risk of a material impairment; however, of the $4.02 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31,
2023, approximately $368 million is recorded in reporting units for which the estimated fair value exceeded the carrying value by approximately 20% or
less in the most recent quantitative test.
Estimated Useful Lives of Long-Lived Assets. Depreciation and amortization of long-lived assets is provided using the straight-line method based on their
estimated useful lives. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. The Partnership’s results
of operations have not been significantly impacted by changes in the estimated useful lives of our long-lived assets during the periods presented, and we do
not anticipate any such significant changes in the future. However, changes in facts and circumstances could cause us to change the estimated useful lives
of the
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Index to Financial Statements
assets, which could significantly impact the Partnership’s results of operations. Additional information on our accounting policies and the estimated useful
lives associated with our long-lived assets is available in Note 2 to our consolidated financial statements in “Item 8. Financial Statements and
Supplementary Data.”
Legal and Regulatory Matters. We are subject to litigation and regulatory proceedings as a result of our business operations and transactions. We utilize
both internal and external counsel in evaluating our potential exposure to adverse outcomes from claims, orders, judgments or settlements. To the extent
that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We
expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us. The factors we
consider when recording an accrual for contingencies include, among others: (i) the opinions and views of our legal counsel; (ii) our previous experience;
and (iii) the decision of our management as to how we intend to respond to the complaints. As of December 31, 2023 and 2022, accruals of $285 million
and $200 million, respectively, were reflected in our consolidated balance sheets related to these contingent obligations.
For more information on our litigation and contingencies, see Note 11 to our consolidated financial statements included in “Item 8. Financial Statements
and Supplementary Data” in this annual report.
Environmental Remediation Activities. The Partnership’s accrual for environmental remediation activities reflects anticipated work at identified sites
where an assessment has indicated that cleanup costs are probable and reasonably estimable. The accrual for known claims is undiscounted and is based on
currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and
regulations. It is often extremely difficult to develop reasonable estimates of future site remediation costs due to changing regulations, changing
technologies and their associated costs, and changes in the economic environment. Engineering studies, historical experience and other factors are used to
identify and evaluate remediation alternatives and their related costs in determining the estimated accruals for environmental remediation activities.
Losses attributable to unasserted claims are generally reflected in the accruals on an undiscounted basis, to the extent they are probable of occurrence and
reasonably estimable. We have established a wholly owned captive insurance company to bear certain risks associated with environmental obligations
related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that
have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses
attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
In general, each remediation site/issue is evaluated individually based upon information available for the site/issue and no pooling or statistical analysis is
used to evaluate an aggregate risk for a group of similar items (e.g., service station sites) in determining the amount of probable loss accrual to be recorded.
The Partnership’s estimates of environmental remediation costs also frequently involve evaluation of a range of estimates. In many cases, it is difficult to
determine that one point in the range of loss estimates is more likely than any other. In these situations, existing accounting guidance requires that the
minimum of the range be accrued. Accordingly, the low end of the range often represents the amount of loss which has been recorded. The Partnership’s
consolidated balance sheets reflected $277 million and $282 million in environmental accruals as of December 31, 2023 and 2022, respectively.
Total future costs for environmental remediation activities will depend upon, among other things, the identification of any additional sites, the
determination of the extent of the contamination at each site, the timing and nature of required remedial actions, the nature of operations at each site, the
technology available and needed to meet the various existing legal requirements, the nature and terms of cost-sharing arrangements with other potentially
responsible parties, the availability of insurance coverage, the nature and extent of future environmental laws and regulations, inflation rates, terms of
consent agreements or remediation permits with regulatory agencies and the determination of the Partnership’s liability at the sites, if any, in light of the
number, participation level and financial viability of the other parties. The recognition of additional losses, if and when they were to occur, would likely
extend over many years. Management believes that the Partnership’s exposure to adverse developments with respect to any individual site is not expected
to be material. However, if changes in environmental laws or regulations occur or the assumptions used to estimate losses at multiple sites are adjusted,
such changes could impact multiple facilities, formerly owned facilities and third-party sites at the same time. As a result, from time to time, significant
charges against income for environmental remediation may occur; however, management does not believe that any such charges would have a material
adverse impact on the Partnership’s consolidated financial position.
Deferred Income Taxes. Energy Transfer recognizes benefits in earnings and related deferred tax assets for net operating loss carryforwards (“NOLs”) and
tax credit carryforwards. If necessary, a charge to earnings and a related valuation allowance are recorded to reduce deferred tax assets to an amount that is
more likely than not to be realized by the Partnership in the future. Deferred income tax assets attributable to state and federal NOLs and federal excess
business interest expense carryforwards
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totaling $371 million have been included in Energy Transfer’s consolidated balance sheet as of December 31, 2023. The state NOL carryforward benefits
of $96 million ($75 million net of federal benefit) began expiring in 2023 with a substantial portion expiring between 2033 and 2039. Energy Transfer’s
corporate subsidiaries have federal NOLs of $1.4 billion ($291 million in benefits), all of which was generated in 2018 or later. A total of $341 million of
the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal net operating loss,
the amount utilized in a particular year may be limited. Any federal NOL generated in 2018 and future years can be carried forward indefinitely. In making
the assessment of the future realization of the deferred tax assets, we rely on future reversals of existing taxable temporary differences, tax planning
strategies and forecasted taxable income based on historical and projected future operating results. The potential need for valuation allowances is regularly
reviewed by management. If it is more likely than not that the recorded asset will not be realized, additional valuation allowances which increase income
tax expense may be recognized in the period such determination is made. Likewise, if it is more likely than not that additional deferred tax assets will be
realized, an adjustment to the deferred tax asset will increase income in the period such determination is made.
Forward-Looking Statements
This annual report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as
assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate
strictly to historical or current facts. When used in this annual report, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,”
“intend,” “could,” “believe,” “may,” “will” and similar expressions and statements regarding our plans and objectives for future operations, are intended to
identify forward-looking statements. Although we and our General Partner believe that the expectations on which such forward-looking statements are
based are reasonable, neither we nor our General Partner can give assurances that such expectations will prove to be correct. Forward-looking statements
are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove
incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct
bearing on our results of operations and financial condition are:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the ability of our subsidiaries to make cash distributions to us, which is dependent on their results of operations, cash flows and financial condition;
the actual amount of cash distributions by our subsidiaries to us;
the volumes transported on our subsidiaries’ pipelines and gathering systems;
the level of throughput in our subsidiaries’ processing and treating facilities;
the fees our subsidiaries charge and the margins they realize for their gathering, treating, processing, storage and transportation services;
the prices and market demand for, and the relationship between, natural gas and NGLs;
energy prices generally;
impacts of world health events;
the possibility of cyber and malware attacks;
the prices of natural gas and NGLs compared to the price of alternative and competing fuels;
the general level of petroleum product demand and the availability and price of NGL supplies;
the level of domestic oil, natural gas and NGL production;
the availability of imported oil, natural gas and NGLs;
actions taken by foreign oil and gas producing nations;
the political and economic stability of petroleum producing nations;
the effect of weather conditions on demand for oil, natural gas and NGLs;
availability of local, intrastate and interstate transportation systems;
the continued ability to find and contract for new sources of natural gas supply;
availability and marketing of competitive fuels;
the impact of energy conservation efforts;
energy efficiencies and technological trends;
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•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
governmental regulation and taxation;
changes to, and the application of, regulation of tariff rates and operational requirements related to our subsidiaries’ interstate and intrastate pipelines;
hazards or operating risks incidental to the gathering, treating, processing and transporting of natural gas and NGLs;
competition from other midstream companies and interstate pipeline companies;
loss of key personnel;
loss of key natural gas producers or the providers of fractionation services;
reductions in the capacity or allocations of third-party pipelines that connect with our subsidiaries pipelines and facilities;
the effectiveness of risk-management policies and procedures and the ability of our subsidiaries liquids marketing counterparties to satisfy their
financial commitments;
the nonpayment or nonperformance by our subsidiaries’ customers;
risks related to the development of new infrastructure projects or other growth projects, including failure to make sufficient progress to justify
continued development, delays in obtaining customers, increased costs of financing and regulatory, environmental, political and legal uncertainties that
may affect the timing and cost of these projects;
risks associated with the construction of new pipelines, treating and processing facilities or other facilities, or additions to our subsidiaries’ existing
pipelines and their facilities, including difficulties in obtaining permits and rights-of-way or other regulatory approvals and the performance by third-
party contractors;
the availability and cost of capital and our subsidiaries’ ability to access certain capital sources;
a deterioration of the credit and capital markets;
risks associated with the assets and operations of entities in which our subsidiaries own a noncontrolling interests, including risks related to
management actions at such entities that our subsidiaries may not be able to control or exert influence;
the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results and to
successfully integrate acquired businesses;
changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or new
interpretations by regulatory agencies concerning such laws and regulations;
the costs and effects of legal and administrative proceedings; and
risks associated with a potential failure to successfully combine our business with that of Crestwood.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risks described
under “Item 1A. Risk Factors” in this annual report. Any forward-looking statement made by us in this Annual Report on Form 10-K is based only on
information currently available to us and speaks only as of the date on which it is made. We undertake no obligation to publicly update any forward-looking
statement, whether written or oral, that may be made from time to time, whether as a result of new information, future developments or otherwise.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
(Tabular dollar amounts are in millions)
Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risk and
interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage
our exposure to such risks.
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various
exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at
fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge
inception, we lock in a margin by purchasing gas in the spot market or off-peak season and entering into a financial contract. Changes in the spreads
between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is
withdrawn and the related designated derivatives are
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settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are
realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and
operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream
segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at
market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are
not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined
products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting
purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to
lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated as
hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate transportation
and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing
activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the
use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings volatility that can occur may be
significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss
reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our
commodity risk management policy.
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The following tables summarize commodity-related financial derivative instruments, fair values and the effect of an assumed hypothetical 10% change in
the underlying price of the commodity as of December 31, 2023 and 2022 for the Partnership and its consolidated subsidiaries. Dollar amounts are
presented in millions.
December 31, 2023
Fair Value
Asset
(Liability)
Effect of
Hypothetical 10%
Change
Notional Volume
December 31, 2022
Fair Value
Asset
(Liability)
Notional Volume
Effect of
Hypothetical 10%
Change
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
(1)
Fixed Swaps/Futures
Basis Swaps IFERC/NYMEX
Swing Swaps
Options – Puts
Option - Calls
Power (Megawatt):
Forwards
Futures
Options – Puts
Options – Calls
Crude (MBbls):
Option - Puts
Option - Calls
NGL/Refined Products (MBbls):
Option - Puts
Option - Calls
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX
Swing Swaps IFERC
Fixed Swaps/Futures
Forward Physical Contracts
NGL (MBbls) – Forwards/Swaps
Crude (MBbls) – Forwards/Swaps
Refined Products (MBbls) – Futures
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX
Fixed Swaps/Futures
(1,878) $
4 $
(171,185)
(900)
1,900
250
155,600
(464,897)
136,000
—
(15)
(20)
121
(43)
124,210
(96,828)
7,125
(1,751)
(13,870)
(2,674)
(4,548)
(39,013)
(39,013)
16
—
(2)
—
1
—
—
—
—
—
(1)
(1)
4
18
12
8
20
8
17
1
45
—
4
—
—
—
—
1
—
—
—
—
—
—
1
1
2
1
43
5
38
1
9
145 $
(39,563)
—
—
—
—
(21,384)
119,200
—
—
—
—
—
42,440
(202,815)
(15,758)
2,423
6,934
795
(3,547)
(37,448)
(37,448)
— $
54
—
—
—
1
—
—
—
—
—
—
—
(41)
63
51
8
(41)
26
(39)
22
58
—
3
—
—
—
—
—
—
—
—
—
—
—
4
7
7
1
63
22
37
2
17
(1)
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub
locations.
The fair values of the commodity-related financial positions have been determined using independent third-party prices, readily available market
information and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical
exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10% change (increase or decrease) in price
regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in
absolute terms and represent a potential gain or loss in net income or in other comprehensive income. In the event of an actual 10% change in prompt
month
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natural gas prices, the fair value of our total derivative portfolio may not change by 10% due to factors such as when the financial instrument settles and the
location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.
Interest Rate Risk
As of December 31, 2023, we and our subsidiaries had $3.29 billion of floating rate debt outstanding. A hypothetical change of 100 basis points would
result in a maximum potential change to interest expense of $33 million annually; however, our actual change in interest expense may be less in a given
period due to interest rate floors included in our variable rate debt instruments. We manage a portion of our interest rate exposure by utilizing interest rate
swaps, including forward-starting interest rate swaps to lock-in the rate on a portion of anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding (including USAC’s), none of which were designated as hedges for accounting purposes
(dollar amounts presented in millions):
Term
Energy Transfer
July 2024
(1)
USAC
December 2025
Type
Notional Amount Outstanding
December 31, 2023 December 31, 2022
Forward-starting to pay a fixed rate of 3.388% and receive a floating rate based on
SOFR
$
— $
Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR
700
400
—
(1)
The July 2024 interest rate swaps were terminated and settled in August 2023.
A hypothetical change of 100 basis points in interest rates for USAC’s interest rate swap would result in a net change in the fair value of interest rate
derivatives and earnings (recognized in gains on interest rate derivatives) of $15 million as of December 31, 2023. For the forward-starting interest rate
swaps, a hypothetical change of 100 basis points in interest rates would not affect cash flows until the swaps are settled.
As of December 31, 2023, the Partnership also had outstanding Series A Preferred Units, Series C Preferred Units and Series D Preferred Units with
aggregate liquidation preferences of $950 million, $450 million and $445 million, respectively, for which distributions are based on a floating rate. A
hypothetical change of 100 basis points in interest rates would result in a net change in preferred unit distributions of $18 million annually for the Series A
Preferred Units, Series C Preferred Units and Series D Preferred Units in the aggregate. Excluding the Series C Preferred Units and the Series D Preferred
Units (both of which were redeemed in February 2024), a hypothetical change of 100 basis point would result in a net change of $10 million in Series A
Preferred Unit distributions only.
As of December 31, 2023, the Partnership had $600 million of Floating Rate Junior Subordinated Notes outstanding, as well as the Series A Preferred
Units, Series C Preferred Units and Series D Preferred Units, the floating rates for each of which were based on the three-month SOFR rate plus a
0.26161% tenor spread adjustment. Such tenor spread adjustment will be in addition to the applicable spread for each series of Preferred Units and Floating
Rate Junior Subordinated Notes.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been
approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish
guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of
existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according to the risk
profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary.
The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a
single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a
single counterparty or affiliated group of counterparties.
Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities. In
addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including
petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power
generators. Our overall exposure may be affected
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positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not
anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our
consolidated balance sheets and recognized in net income or other comprehensive income.
The financial statements starting on page F-1 of this report are incorporated by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
Evaluation of Disclosure Controls and Procedures
ITEM 9A. CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the participation of our management, including Marshall S. McCrea, III and Thomas E. Long,
Co-Chief Executive Officers of our General Partner (Co-Principal Executive Officers), and Dylan A. Bramhall (Principal Financial Officer), of the
effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rules 13a–15(e) and 15d–15(e) of the
Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, management, including Messrs. McCrea, Long and Bramhall,
concluded that our disclosure controls and procedures were adequate and effective as of December 31, 2023.
Management’s Report on Internal Control over Financial Reporting
The management of Energy Transfer LP and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting,
as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the Co-Chief
Executive Officers and Chief Financial Officer of our General Partner, we conducted an evaluation of the effectiveness of our internal control over financial
reporting based on the framework in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO Framework”).
On November 3, 2023, Energy Transfer LP completed its acquisition of Crestwood. Management acknowledges that it is responsible for establishing and
maintaining a system of internal controls over financial reporting for Crestwood. We are in the process of integrating Crestwood, and we therefore have
excluded Crestwood from our December 31, 2023 assessment of the effectiveness of internal control over financial reporting. Crestwood had total assets of
$8.24 billion as of December 31, 2023 and third-party revenues of $789 million from November 3, 2023 to December 31, 2023, which are included in our
consolidated financial statements as of and for the year ended December 31, 2023. The impact of the acquisition of Crestwood has not materially affected
and is not expected to materially affect our internal control over financial reporting. As a result of these integration activities, certain controls are being
evaluated and may be changed. We believe, however, that we will be able to maintain sufficient controls over the substantive results of our financial
reporting throughout this integration process.
Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of
December 31, 2023.
Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of
December 31, 2023, as stated in their report, which is included herein.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of LE GP, LLC and
Unitholders of Energy Transfer LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as
of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated
financial statements of the Partnership as of and for the year ended December 31, 2023, and our report dated February 16, 2024 expressed an unqualified
opinion on those financial statements.
Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness
of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our
responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an
understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We
believe that our audit provides a reasonable basis for our opinion.
Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not include the internal control over financial reporting of
Crestwood Equity Partners LP (“Crestwood”), a consolidated subsidiary, whose financial statements reflect total assets and revenues constituting seven
percent and one percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2023. As indicated
in Management’s Report on Internal Control over Financial Reporting, Crestwood was acquired during 2023. Management’s assertion on the effectiveness
of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of Crestwood.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control
over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial
statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Dallas, Texas
February 16, 2024
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Changes in Internal Controls over Financial Reporting
There has been no change in our internal controls over financial reporting (as defined in Rules 13a–15(f) or Rule 15d–15(f)) that occurred in the three
months ended December 31, 2023 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
Not applicable.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
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Board of Directors
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
PART III
Our general partner, LE GP, LLC, manages and directs all of our activities. The officers and directors of Energy Transfer are officers and directors of LE
GP, LLC. The members of our general partner elect our general partner’s Board of Directors. The board of directors of our general partner has the authority
to appoint our executive officers, subject to provisions in the limited liability company agreement of our general partner. Pursuant to other authority, the
board of directors of our general partner may appoint additional management personnel to assist in the management of our operations and, in the event of
the death, resignation or removal of our chief executive officer, to appoint a replacement.
As of January 1, 2024, our Board of Directors is comprised of nine persons, four of whom qualify as “independent” under the NYSE’s corporate
governance standards. As a limited partnership, we are not required under the NYSE’s corporate governance standards (Section 303A) to have a majority of
independent directors. We have determined that Messrs. Anderson, Brannon, Grimm and Perry are all “independent” under the NYSE’s corporate
governance standards.
As a limited partnership, we are not required by the rules of the NYSE to seek Unitholder approval for the election of any of our directors. We believe that
the members of our general partner have appointed as directors individuals with experience, skills and qualifications relevant to the business of Energy
Transfer, such as experience in energy or related industries or with financial markets, expertise in natural gas operations or finance, and a history of service
in senior leadership positions. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration
of diversity in identifying director nominees, but we believe that the members of our general partner have endeavored to assemble a group of individuals
with the qualities and attributes required to provide effective oversight of Energy Transfer.
Board Leadership Structure. We have no policy requiring either that the positions of the Chairman of the Board and the Chief Executive Officer, or CEO,
be separate or that they be occupied by the same individual. The Board of Directors believes that this issue is properly addressed as part of the succession
planning process and that a determination on this subject should be made when it elects a new chief executive officer or at such other times as when
consideration of the matter is warranted by circumstances. Previously, the Board of Directors believed that the CEO was best situated to serve as Chairman
because he was the director most familiar with the Partnership’s business and industry, and most capable of effectively identifying strategic priorities and
leading the discussion and execution of strategy. Beginning in 2021, the Board of Directors has established separate roles for the Executive Chairman and
Co-Chief Executive Officers. Independent directors and management have different perspectives and roles in strategy development. Our independent
directors bring experience, oversight and expertise from outside the Partnership and from a variety of industries, while the Executive Chairman and Co-
Chief Executive Officers bring extensive experience and expertise specifically related to the Partnership’s business.
Risk Oversight. Our Board of Directors generally administers its risk oversight function through the board as a whole. Our Co-CEOs, who report to the
Board of Directors, have day-to-day risk management responsibilities. Our Co-CEOs attend the meetings of our Board of Directors, where the Board of
Directors routinely receives reports on our financial results, the status of our operations, and other aspects of implementation of our business strategy, with
ample opportunity for specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of Energy
Transfer’s financial and operational performance, which often prompts questions or feedback from the Board of Directors. The Audit Committee provides
additional risk oversight through its quarterly meetings, where it receives a report from Energy Transfer’s internal auditor, who reports directly to the Audit
Committee, and reviews Energy Transfer’s contingencies with management and our independent auditors.
Corporate Governance
The Board of Directors has adopted both a Code of Business Conduct and Ethics applicable to our directors, officers and employees, and Corporate
Governance Guidelines for directors and the Board. Current copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines and
charters of the Audit and Compensation Committees of our Board of Directors are available on our website at www.energytransfer.com and will be
provided in print form to any Unitholder requesting such information.
Please note that the preceding internet address is for information purposes only and is not intended to be a hyperlink. Accordingly, no information found
and/or provided at such internet address or contained on our website in general is intended or deemed to be incorporated by reference in this report.
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Annual Certification
In 2023, our Co-Chief Executive Officers provided to the NYSE the annual CEO certification regarding our compliance with the NYSE’s corporate
governance listing standards.
Conflicts Committee
Our Partnership Agreement provides that the Board of Directors may, from time to time, appoint members of the Board to serve on the Conflicts
Committee with the authority to review specific matters for which the Board of Directors believes there may be a conflict of interest in order to determine if
the resolution of such conflict proposed by the general partner is fair and reasonable to Energy Transfer and our Unitholders. As a policy matter, the
Conflicts Committee generally reviews any proposed related-party transaction that may be material to Energy Transfer to determine if the transaction
presents a conflict of interest and whether the transaction is fair and reasonable to Energy Transfer. Pursuant to the terms of our Partnership Agreement, any
matters approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to the Energy Transfer, approved by all partners of
Energy Transfer and not a breach by the general partner or its Board of Directors of any duties they may owe Energy Transfer or the Unitholders. These
duties are limited by our Partnership Agreement (see “Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
Audit Committee
The Board of Directors has established an Audit Committee in accordance with Section 3(a)(58)(A) of the Exchange Act. The Board of Directors appoints
persons who are independent under the NYSE’s standards for audit committee members to serve on its Audit Committee. In addition, the Board determines
that at least one member of the Audit Committee has such accounting or related financial management expertise sufficient to qualify such person as the
audit committee financial expert in accordance with Item 407(d)(5) of Regulation S-K. The Board determined that based on relevant experience, Audit
Committee member Michael K. Grimm qualified as an audit committee financial expert during 2023. A description of the qualifications of Mr. Grimm may
be found elsewhere in this Item 10 under “Directors and Executive Officers of the General Partner.”
The Audit Committee meets on a regularly scheduled basis with our independent accountants at least four times each year and is available to meet at their
request. The Audit Committee has the authority and responsibility to review our external financial reporting, review our procedures for internal auditing
and the adequacy of our internal accounting controls, consider the qualifications and independence of our independent accountants, engage and direct our
independent accountants, including the letter of engagement and statement of fees relating to the scope of the annual audit work and special audit work
which may be recommended or required by the independent accountants, and to engage the services of any other advisors and accountants as the Audit
Committee deems advisable. The Audit Committee reviews and discusses the audited financial statements with management, discusses with our
independent auditors matters required to be discussed by auditing standards, and approves the filing of our Form 10-K, which includes our audited financial
statements. The Audit Committee periodically recommends to the Board of Directors any changes or modifications to its charter that may be required. The
Audit Committee has received written disclosures and the letter from Grant Thornton required by applicable requirements of the Audit Committee
concerning independence and has discussed with Grant Thornton that firm’s independence. The Audit Committee recommended to the Board that the
audited financial statements of Energy Transfer be included in Energy Transfer’s Annual Report on Form 10-K for the year ended December 31, 2023.
The Board of Directors adopts the charter for the Audit Committee. Steven R. Anderson, Richard D. Brannon and Michael K. Grimm serve as elected
members of the Audit Committee.
Compensation and Nominating/Corporate Governance Committees
Although we are not required under NYSE rules to appoint a Compensation Committee or a Nominating/Corporate Governance Committee because we are
a limited partnership, the Board of Directors of LE GP, LLC has previously established a Compensation Committee to establish standards and make
recommendations concerning the compensation of our officers and directors. In addition, the Compensation Committee determines and establishes the
standards for any awards to our employees and officers under the equity compensation plans, including the performance standards or other restrictions
pertaining to the vesting of any such awards. Messrs. Anderson and Grimm serve as members of the Compensation Committee.
The responsibilities of the Energy Transfer Compensation Committee include, among other duties, the following:
•
•
annually review and approve goals and objectives relevant to compensation of our Co-CEOs and CFO, if applicable;
annually evaluate the CEO and CFO’s performance in light of these goals and objectives, and make recommendations to the Board of Directors with
respect to the CEO and CFO’s compensation levels, if applicable, based on this evaluation;
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• make determinations with respect to the grant of equity-based awards to executive officers under Energy Transfer’s equity incentive plans;
•
•
•
•
•
periodically evaluate the terms and administration of Energy Transfer’s long-term incentive plans to assure that they are structured and administered in
a manner consistent with Energy Transfer’s goals and objectives;
periodically evaluate incentive compensation and equity-related plans and consider amendments if appropriate;
periodically evaluate the compensation of the directors;
retain and terminate any compensation consultant to be used to assist in the evaluation of director, CEO and CFO or executive officer compensation;
and
perform other duties as deemed appropriate by the Board of Directors.
Code of Business Conduct and Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics applicable to our officers, directors and employees. Specific provisions are
applicable to the co-principal executive officers, principal financial officer, principal accounting officer and controller, or those persons performing similar
functions, of our general partner. Amendments to, or waivers from, the Code of Business Conduct and Ethics will be available on our website and reported
as may be required under SEC rules. Any technical, administrative or other non-substantive amendments to the Code of Business Conduct and Ethics may
not be posted.
Meetings of Non-management Directors and Communications with Directors
Our non-management directors meet in regularly scheduled sessions. Our non-management directors alternate as the presiding director of such meetings.
We have established a procedure by which Unitholders or interested parties may communicate directly with the Board of Directors, any committee of the
Board, any of the independent directors, or any one director serving on the Board of Directors by sending written correspondence addressed to the desired
person, committee or group to the attention of Sonia Aubé at Energy Transfer LP, 8111 Westchester Drive, Suite 600, Dallas, Texas, 75225.
Communications are distributed to the Board of Directors, or to any individual director or directors as appropriate, depending on the facts and
circumstances outlined in the communication.
Directors and Executive Officers of Our General Partner
The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner as of
February 16, 2024. Executive officers and directors are elected for indefinite terms.
Name
Kelcy L. Warren
Thomas E. Long
Marshall S. (Mackie) McCrea, III
Dylan A. Bramhall
Thomas P. Mason
Bradford D. Whitehurst
James M. Wright, Jr.
A. Troy Sturrock
Steven R. Anderson
Richard D. Brannon
Michael K. Grimm
John W. McReynolds
James R. (Rick) Perry
Matthew S. Ramsey
Age
Position with Our General Partner
68 Executive Chairman of the Board of Directors
67 Co-Chief Executive Officer and Director (Co-Principal Executive Officer)
64 Co-Chief Executive Officer and Director (Co-Principal Executive Officer)
47 Executive Vice President and Group Chief Financial Officer (Principal Financial Officer)
67 Executive Vice President — Alternative Energy and President — LNG
49 Executive Vice President of Tax and Corporate Initiatives
55 Executive Vice President, General Counsel and Chief Compliance Officer
53 Group Senior Vice President and Controller (Principal Accounting Officer)
74 Director
65 Director
69 Director
73 Director
73 Director
68 Director
Mr. Long, Mr. Mason and Mr. Whitehurst serve as directors of the general partner of USAC.
Set forth below is biographical information regarding the foregoing officers and directors of our general partner:
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Kelcy L. Warren. Mr. Warren serves as Executive Chairman of our general partner. Mr. Warren served as Chief Executive Officer from August 2007
through December 2020. He was appointed Co-Chairman of the Board of Directors of our general partner, effective upon the closing of our IPO, and in
August 2007, he became the sole Chairman of the Board of our general partner and the Chief Executive Officer and Chairman of the Board of the general
partner of ETO until its merger into Energy Transfer LP in April 2021. Prior to August 2007, Mr. Warren had served as Co-Chief Executive Officer and Co-
Chairman of the Board of the general partner of ETO since the combination of the midstream and intrastate transportation storage operations of La Grange
Acquisition, L.P. and the retail propane operations of Heritage in January 2004. Mr. Warren also served as the Chief Executive Officer of PennTex
Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Warren was selected to serve as a director and as Executive Chairman
because he previously served as Chief Executive Officer and has more than 30 years in the natural gas industry. Mr. Warren also has relationships with
chief executives and other senior management at natural gas transportation companies throughout the United States and brings a unique and valuable
perspective to the Board of Directors.
Thomas E. Long. Mr. Long has served as the Co-Chief Executive Officer of our general partner since January 2021. Mr. Long served as Chief Financial
Officer of Energy Transfer’s general partner from February 2016 until January 2021, and has been a director of our general partner since April 2019. Mr.
Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017.
Mr. Long also served as Chief Financial Officer of ETO until its merger into Energy Transfer LP in April 2021, and was previously Executive Vice
President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015. Mr. Long served as a director of Sunoco LP from May
2016 until May 2021, and has served on the Board of USAC since April 2018. In May 2022, Mr. Long was appointed to the board of directors of Texas
Capital Bancshares, Inc (NASDAQ: TCBI). Mr. Long was selected to serve on our Board of Directors because of his understanding of energy-related
corporate finance gained through his extensive experience in the energy industry.
Marshall S. (Mackie) McCrea, III. Mr. McCrea has served as the Co-Chief Executive Officer of our general partner since January 2021. Prior to that he
was the President and Chief Commercial Officer of our general partner, having served in that role since October 2018 following the merger of Energy
Transfer Equity, L.P. and Energy Transfer Partners, L.P. Prior to that time, he had been the Group Chief Operating Officer and Chief Commercial Officer of
the Energy Transfer family since November 2015. Mr. McCrea has served on the Board of Directors of our general partner since December 2009. Mr.
McCrea was appointed as a director of the general partner of ETO in December 2009 and served in that capacity until ETO’s merger into Energy Transfer
LP in April 2021. Prior to December 2009, he served as President and Chief Operating Officer of ETO’s general partner from June 2008 to November 2015
and President – Midstream from March 2007 to June 2008. Previously he served as the Senior Vice President – Commercial Development since January
2004. In March 2005, Mr. McCrea was named President of La Grange Acquisition LP, ETO’s primary operating subsidiary, after serving as Senior Vice
President-Business Development and Producer Services since 1997. Mr. McCrea also served as the Chairman of the Board of Directors of the general
partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017. Mr. McCrea was selected to serve as a director because he brings extensive
project development and operational experience to the Board. He has held various positions in the natural gas business over the past 25 years and is able to
assist the Board of Directors in creating and executing the Partnership’s strategic plan.
Dylan A. Bramhall. Mr. Bramhall has served as Executive Vice President and Group Chief Financial Officer of our general partner since November 2022
and currently is also Chief Financial Officer of Sunoco LP’s general partner. Mr. Bramhall joined Energy Transfer in 2015 as a result of its merger with
Regency Energy Partners and is responsible for oversight of the Partnership’s Financial Planning and Analysis, Credit and Commodity Risk Management,
Insurance, Cash Management, Capital Markets, Accounting, Financial Reporting and Investor Relations groups. He also serves as a member of Energy
Transfer’s Risk Oversight Committee. While at Regency, Mr. Bramhall held management positions in the finance, risk, commercial and operations groups.
Mr. Bramhall holds a Bachelor of Business Administration in finance and Master of Business Administration in finance and operations management, both
from the University of Iowa.
Thomas P. Mason. Mr. Mason has served as Executive Vice President and President - LNG since December 2022. He became Executive Vice President
and General Counsel of the general partner of Energy Transfer in December 2015, and served as the Executive Vice President, General Counsel and
President - LNG from October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. until December 2022 when he
resigned from his role as General Counsel. In February 2021, Mr. Mason assumed leadership responsibility over the Partnership’s newly created
Alternative Energy Group, which focuses on the development of alternative energy projects aimed at continuing to reduce Energy Transfer’s environmental
footprint throughout its operations. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from
April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February
2007. Prior to joining Energy Transfer, he was a partner in the Houston office of Vinson & Elkins. Mr. Mason served as a director on the Board of Directors
of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017 and as a director on the Board of Directors of PennTex Midstream
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Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason has also served as a member of the Board of Directors of USAC since April
2018.
Bradford D. Whitehurst. Mr. Whitehurst has served as Executive Vice President of Tax and Corporate Initiatives of Energy Transfer since November 2022.
From January 2021 to November 2022, he served as Chief Financial Officer. From August 2014 through December 2020, he served as Executive Vice
President – Head of Tax. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an
attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has
advised Energy Transfer and its subsidiaries in his role as outside counsel since 2006. He has served as a member of the board of directors of USAC since
April 2019.
James M. Wright, Jr. Mr. Wright was appointed as Executive Vice President, General Counsel and Chief Compliance Officer of our general partner in
December 2022. He became Executive Vice President - Legal and Chief Compliance Officer of ET’s general partner in October 2018 following the merger
of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Mr. Wright has been a part of the Energy Transfer legal team with increasing levels of
responsibility since July 2005 and has held various senior-level positions in the legal department including General Counsel of the general partner of
Energy Transfer Partners, L.P. from December 2015 to October 2018 and Deputy General Counsel from May 2008 to December 2015. Prior to joining
Energy Transfer, Mr. Wright gained significant experience at Enterprise Products Partners, L.P., El Paso Corp., Sonat Exploration Company and KPMG
Peat Marwick LLP. Mr. Wright earned a Bachelor of Business Administration degree in Accounting and Finance from Texas A&M University and a JD
from South Texas College of Law.
A. Troy Sturrock. Mr. Sturrock has served as the Group Senior Vice President, Controller and Principal Accounting Officer of our general partner since
September 2022. He previously served as Senior Vice President, Controller and Principal Accounting Officer, having assumed that role in October 2018
following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. He served as the Senior Vice President, Controller and Principal
Accounting Officer of the general partner of ETO from August 2016 until ETO’s merger into Energy Transfer LP in April 2021, and previously served as
Vice President, Controller and Principal Accounting Officer of our general partner beginning in June 2015. Mr. Sturrock is a Certified Public Accountant.
Steven R. Anderson. Mr. Anderson was elected to the Board of Directors of our general partner in June 2018 and serves on the audit committee and
compensation committee. Mr. Anderson began his career in the energy business in the early 1970’s with Conoco in the Permian Basin area. He then spent
some 25 years with ANR Pipeline and its successor, The Coastal Corporation, as a natural gas supply and midstream executive. He later was Vice President
of Commercial Operations with Aquila Midstream and, upon the sale of that business to Energy Transfer in 2002, he became a part of the management
team there. For the six years prior to his retirement from Energy Transfer in October 2009, he served as Vice President of Mergers and Acquisitions. Since
that time, he has been involved in private investments and has served on the boards of directors of the St. John Health System and Saint Simeon’s
Episcopal Home in Tulsa, Oklahoma, as well as various other community and civic organizations. Mr. Anderson also served as a member of the board of
directors of Sunoco Logistics Partners L.P. from October 2012 until April 2017. Mr. Anderson was selected to serve on our Board of Directors based on his
experience in the midstream energy industry generally, and his knowledge of Energy Transfer’s business specifically. Mr. Anderson also brings recent
experience on audit and compensation committees of another publicly traded partnership.
Richard D. Brannon. Mr. Brannon was appointed to the Board of Directors of our general partner in March 2016 and has served as the Chairman of the
audit committee since April 2016. Mr. Brannon is the CEO of CH4 Energy Six, LLC and Uinta Wax, LLC, both independent companies focused on
horizontal oil and gas development. Mr. Brannon previously served on the board of directors of WildHorse Resource Development from its IPO in
December 2016 until June 2018. Mr. Brannon also formerly served on the Board of Directors and as a member of the audit committee and compensation
committee of Sunoco LP, Regency, OEC Compression and Cornerstone Natural Gas Corp. He has over 35 years of experience in the energy business,
having started his career in 1981 with Texas Oil & Gas. The members of our general partner selected Mr. Brannon to serve as director based on his
knowledge of the energy industry and his experience as a director and audit and compensation committee member for other public companies.
Michael K. Grimm. Mr. Grimm was appointed to the Board of Directors of our general partner in October 2018, and has served on the audit committee and
compensation committee since that time. Prior to that time, Mr. Grimm served as a director of ETO’s general partner beginning in December 2005, and
served on the audit and compensation committee during that time. Mr. Grimm is one of the original founders of Rising Star Energy, L.L.C., a privately held
upstream exploration and production company active in onshore continental United States, and served as its President and Chief Executive Officer from
1995 until 2006 when it was sold. Mr. Grimm is currently President of Rising Star Petroleum, LLC. Mr. Grimm was formerly Chairman of the Board of
RSP Permian, Inc. (NYSE: RSPP) from January 2014 until June 2018. From November 2018 until it was sold in 2019, Mr. Grimm served on the Board of
Directors of Anadarko Petroleum Corporation. Prior to the formation of Rising Star,
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Mr. Grimm was Vice President of Worldwide Exploration and Land for Placid Oil Company from 1990 to 1994. Prior to joining Placid Oil Company, Mr.
Grimm was employed by Amoco Production Company for thirteen years where he held numerous positions throughout the exploration department in
Houston, New Orleans and Chicago. Mr. Grimm has been an active member of the American Association of Professional Landmen, Dallas Wildcat
Committee, Dallas Producers Club, and the All-American Wildcatters. He has a B.B.A. from the University of Texas at Austin. Mr. Grimm was selected to
serve as a director because of his extensive experience in the energy industry and his service as a senior executive at several energy-related companies, in
addition to his contacts in the industry gained through his involvement in energy-related organizations.
John W. McReynolds. Mr. McReynolds is a director of Energy Transfer LP, having served in that capacity since August 2004. Mr. McReynolds previously
served as the President of Energy Transfer LP from March 2005 until October 2018, at which time he became Special Advisor to the Partnership. Mr.
McReynolds also previously served as our Chief Financial Officer from August 2005 to June 2013. Prior to becoming President of Energy Transfer LP, Mr.
McReynolds was a partner in the international law firm of Hunton & Williams LLP for over 20 years. As a lawyer, he specialized in energy related finance,
securities, partnerships, mergers and acquisitions, syndication and litigation matters, and served as an expert in numerous arbitration, litigation, and
governmental proceedings, including as an expert in special projects for boards of directors of public companies. Mr. McReynolds was selected to serve in
the indicated roles with Energy Transfer because of this extensive background and experience, as well as his many contacts and relationships in the
industry.
James R. (Rick) Perry. Mr. Perry was appointed to the Board of Directors of our general partner in January 2020. He formerly served as U.S. Secretary of
Energy from March 2017 until December 2019. Prior to that, he served as the Governor of the State of Texas from 2000 until January 2015. Mr. Perry
served as Lieutenant Governor of Texas from 1998 to 2000, and as Agriculture Commissioner from 1991 to 1998. Prior to 1991, he also served in the Texas
House of Representatives. Mr. Perry previously served on the Board of Directors of ETO from February 2015 until December 2016. Mr. Perry was selected
to serve as a director because of his vast experience as an executive in the highest office of state government. In addition, Mr. Perry has been involved in
finance and budget planning processes throughout his career in government as a member of the Texas House Appropriations Committee, the Legislative
Budget Board and as Governor.
Matthew S. Ramsey. Mr. Ramsey was appointed as a director of Energy Transfer’s general partner in July 2012 and served as a director of ETO’s general
partner from November 2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey served as the Chief Operating Officer or our general
partner from October 2018 until his retirement in April 2022, and served as President and Chief Operating Officer of ETO’s general partner from
November 2015 until its merger into Energy Transfer LP in April 2021. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of
the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey also previously served as a
director of Sunoco LP, having served as chairman of Sunoco LP’s board from April 2015 until March 2022, and of USAC, having served on that board
from April 2018 until March 2022. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and
previously served as a director of RSP Permian, Inc. where he served on the audit and compensation committees. In addition to his work in the energy
business, Mr. Ramsey formerly served on the board of directors of the National Association of Manufacturers, and he is currently a Trustee of the
Southwestern Medical Foundation. He is the former Chairman of the University of Texas Chancellor’s Council. Mr. Ramsey holds a B.B.A. in Marketing
from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey was selected to serve based on vast experience in the oil
and gas space and Energy Transfer believes that he provides valuable industry insight as a member of our Board of Directors.
Delinquent Section 16(a) Reports
Section 16(a) of the Securities Exchange Act of 1934 requires the directors and executive officers of our general partner, as well as persons who own more
than ten percent of the common units representing limited partnership interests in us, to file reports of ownership and changes of ownership on Forms 3, 4
and 5 with the SEC. The SEC regulations also require that copies of these Section 16(a) reports be furnished to us by such reporting persons. Based upon a
review of copies of these reports, we believe all applicable Section 16(a) reports were timely filed in 2023, except for one late Form 4 filing by each
Messrs. McReynolds and Wright.
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Compensation Discussion and Analysis
Named Executive Officers
ITEM 11. EXECUTIVE COMPENSATION
Energy Transfer does not have officers or directors. Instead, we are managed by the board of directors of our General Partner, and the executive officers of
our General Partner perform all of Energy Transfer’s management functions. As a result, the executive officers of our General Partner are Energy Transfer’s
executive officers, and their compensation is administered by our General Partner. This Compensation Discussion and Analysis is, therefore, focused on the
total compensation of the executive officers of our General Partner as set forth below. The persons we refer to in this discussion as our “named executive
officers” are the following:
• Marshall S. (Mackie) McCrea, III, Co-Chief Executive Officer;
•
Thomas E. Long, Co-Chief Executive Officer;
• Dylan A. Bramhall, Executive Vice President and Group Chief Financial Officer;
•
•
•
Bradford D. Whitehurst, Executive Vice President — Tax and Corporate Initiatives;
Thomas P. Mason, Executive Vice President — Alternative Energy and President — LNG; and
James M. Wright, Jr., Executive Vice President, General Counsel and Chief Compliance Officer.
Our Philosophy for Compensation of Executives
In general, our General Partner’s philosophy for executive compensation is based on the premise that a significant portion of each executive’s
compensation should be incentive-based or “at-risk” compensation and that executives’ total compensation levels should be highly competitive in the
marketplace for executive talent and abilities. Our General Partner seeks a total compensation program for its executive officers, including the named
executive officers, that provides for a slightly below the median market annual base compensation (i.e., approximately the 30 to 40 percentile of market)
but incentive-based compensation composed of a combination of compensation vehicles to reward both short- and long-term performance that are both
targeted to pay out at approximately the top-quartile of market. Our General Partner believes the incentive-based balance is achieved by (i) the payment of
annual discretionary cash bonuses that consider the achievement of the Partnership’s financial performance objectives for a fiscal year set at the beginning
of such fiscal year and the individual contributions of its executive officers, including the named executive officers, to the success of the Partnership and
the achievement of the annual financial performance objectives and (ii) the annual grant of time-based restricted unit, phantom unit awards or cash
restricted unit awards under the Partnership’s equity incentive plan(s) or the equity incentive programs of Sunoco LP, as applicable based on the allocation
of executive officers awards, including awards to the named executive officers, which awards are intended to provide a longer term incentive and retention
value to its key employees to focus their efforts on increasing the market price of its publicly traded units and to increase the cash distribution the
Partnership and/or the other affiliated partnerships pay to their respective unitholders.
th
th
The Partnership has historically granted restricted unit and/or phantom unit awards (“RSUs”) that vest, based generally upon continued employment, at a
rate of 60% after the third year of service and the remaining 40% after the fifth year of service. Beginning in 2020, Energy Transfer began granting cash
restricted units (“CRSUs”) that vest, based generally upon continued employment, at a rate of 1/3 annually over a three-year period. For 2020, the awards
to employees were generally split equally between RSUs and CRSUs; subsequent to 2020, the awards are generally split based on 75% RSUs and 25%
CRSUs. The Partnership believes that these equity-based incentive arrangements are important in attracting and retaining executive officers and key
employees as well as motivating these individuals to achieve stated business objectives. The equity-based compensation reflects the importance our
General Partner places on aligning the interests of its named executive officers with those of Unitholders. While the Partnership utilizes time-based forms
of equity awards, the grant date valuation utilizes a modified total unitholder return (“TUR”) performance as measured against the average return of Energy
Transfer’s identified peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity
awards based on the prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs
themselves are a time-vested vehicle.
As discussed below, our compensation committee and/or the compensation committee of the general partner of Sunoco LP, as applicable, all in consultation
with our General Partner, are responsible for the compensation policies and compensation level of our executive officers, including the named executive
officers of our General Partner. In this discussion, we refer to our compensation committee as the “Energy Transfer Compensation Committee.”
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For a more detailed description of the compensation to the Partnership’s named executive officers, please see “– Compensation Tables” below.
Distributions to Our General Partner
Our General Partner is majority-owned by Mr. Kelcy Warren. We pay quarterly distributions to our General Partner in accordance with our Partnership
Agreement with respect to its ownership of its general partner interest as specified in our Partnership Agreement. The cash distributions we make to our
General Partner bear no relationship to the level or components of compensation of our General Partner’s executive officers. Distributions to our General
Partner are described in detail in Note 8 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” Our
named executive officers also own directly and indirectly certain of our limited partner interests and, accordingly, receive quarterly distributions. Such per-
unit distributions equal the per-unit distributions made to all our limited partners and bear no relationship to the level of compensation of the named
executive officers or the services they perform as employees.
For a more detailed description of the compensation of our named executive officers, please see “– Compensation Tables” below.
Compensation Philosophy
Our compensation programs are structured to achieve the following:
•
•
reward executives with an industry-competitive total compensation package of base salaries and significant incentive opportunities yielding a total
compensation package approaching the top-quartile of the market;
attract, retain and reward talented executive officers and key management employees by providing total compensation competitive with that of other
executive officers and key management employees employed by publicly traded limited partnerships or other peer companies of similar size and in
similar lines of business;
• motivate executive officers and key employees to achieve strong financial and operational performance;
•
•
emphasize performance-based, or “at-risk,” compensation; and
reward individual performance.
Components of Executive Compensation
For the year ended December 31, 2023, the compensation paid to our named executive officers consisted of the following components:
•
•
•
•
•
•
annual base salary;
non-equity incentive plan compensation consisting solely of discretionary cash bonuses;
time-vested RSUs and CRSUs under the equity incentive plan(s);
payment of distribution equivalent rights (“DERs”) on unvested time-based RSUs under our equity incentive plan;
vesting of previously issued time-based RSUs issued pursuant to our equity incentive plans or the equity incentive plans(s) of affiliates; and
401(k) plan employer contributions.
Methodology
The Energy Transfer Compensation Committee considers relevant data available to it to assess our competitive position with respect to base salary, annual
short-term incentives and long-term incentive compensation for our executive officers, including the named executive officers. The Energy Transfer
Compensation Committee also considers individual performance, levels of responsibility, skills and experience.
Periodically, the Energy Transfer Compensation Committee engages a third-party independent compensation consultant to provide a full market
competitive compensation analysis for compensation levels at peer companies in order to assist in the determination of compensation levels for our
executive officers, including the named executive officers. Most recently, in 2023 Meridian Compensation Partners, LLC (“Meridian”) completed an
evaluation of the market competitiveness of total compensation levels of a number of officers of the Partnership, including the named executive officers.
The Meridian review provided market information with respect to compensation of Partnership executives, including named executive officers during the
year ended December 31, 2023. In particular, the review by Meridian was designed to (i) evaluate the market competitiveness of total compensation levels
for certain members of senior management, including our named executive
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officers; (ii) assist in the determination of appropriate compensation levels for our senior management, including the named executive officers; and (iii)
confirm that our compensation programs were yielding compensation packages consistent with our overall compensation philosophy.
In conducting its review, Meridian assisted in the development of the final “peer group” of leading companies in the energy industry that most closely
reflect the profile of Energy Transfer. The final “peer group” consisted of the core group of peers (i.e. the eight most similar peers in terms of business,
revenues, assets and market value as well as competition for talent at the senior management level) and a group of expanded reference companies
composed of a broader group of oil and gas companies, including additional integrated, upstream and midstream comparators whose data provided
additional market context. As part of the evaluation conducted by Meridian, a determination was made to focus the analysis largely on the core energy
industry peers. This decision was based on a determination that the core peer group provided a more than sufficient amount of comparative data to consider
and evaluate total compensation. This focus allowed Meridian to report on this specific core peer data comparing the levels of annual base salary, annual
short-term cash bonus and long-term equity incentive awards at industry peer group companies with those of the named executive officers to ensure that
compensation of the named executive officers is both consistent with the compensation philosophy and competitive with the compensation for executive
officers of these other companies, while at the same time considering whether the context provided by the expanded group offered additional information
that should be considered by the Compensation Committee. The core identified companies were:
Energy Peer Group:
• Conoco Phillips
• Enterprise Products Partners, L.P.
• Plains All American Pipeline, L.P.
• Valero Energy Corporation
• Marathon Petroleum Corporation
• Kinder Morgan, Inc.
• The Williams Companies, Inc.
• Phillips 66
The compensation analysis provided by Meridian covered all major components of total compensation, including annual base salary, annual short-term
cash bonus and long-term incentive awards for the senior executives. In preparing the review materials, Meridian utilized generally accepted compensation
principles and gathered data from public disclosures of peer companies, including Form 10-K and proxy data and published survey data from multiple
sources that are relevant to Energy Transfer’s core peer group, industry, financial size and operational breadth. The Meridian review process also included
significant engagement with management to fully understand job scope, responsibilities and roles of each of the executive officers, which discussions allow
Meridian the ability to completely evaluate specific aspects of an executive officer’s position to allow for more accurate comparisons.
Following Meridian’s 2023 review, the Energy Transfer Compensation Committee reviewed the information provided, including Meridian’s specific
summary observations and recommended considerations for all compensation going forward. The observations addressed overall competitive
benchmarking, peer company approaches to compensation and short and long-term incentive plan design, the Energy Transfer Compensation Committee
considered and reviewed the results of the study performed by Meridian to determine if the results indicated that the compensation programs were yielding
a competitive total compensation model prioritizing incentive-based compensation and rewarding achievement of short and long-term performance
objectives and considered Meridian’s conclusions and recommendations. While Meridian found that the Partnership is continuing to achieve its stated
objectives with respect to the “at-risk” approach, Meridian also recommended certain adjustments for consideration, which considerations were designed to
allow the Partnership to continue to achieve its targeted percentiles on base compensation and incentive compensation (short and long-term). In respect of
the 2023 Meridian review, the Energy Transfer Compensation Committee, in consultation with Meridian and executive management, approved the adoption
of the Amended and Restated Energy Transfer LP Annual Bonus Plan (the “Amended Bonus Plan”) effective as January 1, 2023. The Amended Bonus
Plan enhanced potential pay-out for achievement of specific performance goals allowing for a maximum Amended Bonus Plan payout of 130% of target as
opposed to the prior Bonus Plan maximum payout of 116%. Specific changes are discussed below under the title of Annual Bonus. Certain of Meridian’s
other suggested considerations as part of the review were implemented and others were determined to require additional review and consideration.
In addition to the information received as part of Meridian’s review, the Energy Transfer Compensation Committee also utilizes information obtained from
other sources in its determination of compensation levels for our named executive officers, such as annual third-party surveys, although third-party survey
data is not used by the Energy Transfer Compensation Committee to benchmark the amount of total compensation or any specific element of compensation
for the named executive officers.
Base Salary. Base salary is designed to provide for a competitive fixed level of pay that attracts and retains executive officers and compensates them for
their level of responsibility and sustained individual performance (including experience, scope of responsibility and results achieved). The salaries of the
named executive officers are reviewed on an annual basis. As discussed
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above, the base salaries of our named executive officers are targeted to yield an annual base salary slightly below the median level of market (i.e.,
approximately the 30 to 40 percentile of market) and are determined by the Energy Transfer Compensation Committee after taking into account the
recommendations of Mr. Warren.
th
th
During the merit review process, the Energy Transfer Compensation Committee considers the recommendations of Mr. Warren, any relevant compensation
study data (with the data aged as appropriate) and the merit increase pool set for all employees of the Partnership and/or its employing affiliates. During
2023, the Energy Transfer Compensation Committee approved a 4.75% increase to the base salary of Mr. McCrea to $1,465,788 from the prior level of
$1,399,320; a 4.75% increase to the base salary of Mr. Long to $1,465,788 from the previous level of $1,399,320; an approximately 6.75% increase to the
base salary of Mr. Bramhall to $613,813 from the previous level of $575,000; and an approximately 4.75% increase to the base salary of Mr. Wright to
$576,125 from the previous level of $550,000. In the case of Messrs. Whitehurst and Mason, the Energy Transfer Compensation Committee approved
lump-sum cash payments equal to 4.75 % of their existing base salaries, which for Mr. Whitehurst such lump sum was $30,420 and for Mr. Mason was
$32,285. The determination regarding the lump-sum payments to Messrs. Whitehurst and Mason were related to certain changes to their roles and
responsibilities and the results of the Meridian benchmarking analysis.
Executive Compensation Clawback Policy. In November 2023, the Energy Transfer Compensation Committee adopted the Energy Transfer Executive
Officer Incentive Compensation Clawback Policy (the “Clawback Policy”), which requires the Partnership to recover erroneously awarded incentive-based
compensation from executive officers in the event the Partnership is required to prepare an accounting restatement. The Clawback Policy applies to any
individual who is currently or was previously designated as an “officer” of the Partnership as defined in Rule 16a-1(f) under the Securities Exchange Act of
1934, including all of our current NEOs. The Clawback Policy is designed to comply with the requirements of the SEC and the NYSE Listed Company
Manual, including (i) the definition of an accounting restatement, (ii) the applicable types of incentive-based compensation, (iii) the relevant recovery
period, and (iv) the approach for calculating the recovery amount.
Annual Bonus. In addition to base salary, the Energy Transfer Compensation Committee makes determinations whether to make discretionary annual cash
bonus awards to executives, including our named executive officers, following the end of the year under the Amended Bonus Plan. As noted the Amended
Bonus Plan replaced the Bonus Plan in connection with certain recommendations contained in Merdian’s 2023 review.
The Amended Bonus Plan is a discretionary annual cash bonus plan available to all employees, including the named executive officers. The purpose of the
Amended Bonus Plan is to reward employees for contributions towards the Partnership’s business goals and to aid in motivating employees. The Amended
Bonus Plan is administered by the Energy Transfer Compensation Committee and the Energy Transfer Compensation Committee has the authority to
establish and interpret the rules and regulations relating to the Amended Bonus Plan, to select participants, to determine and approve the size of any actual
award amount, to make all determinations, including factual determinations and to take all other actions necessary or appropriate for the proper
administration of the Amended Bonus Plan.
Prior to January 1, 2023, the Bonus Plan provided during each calendar year or any other period designated by the Energy Transfer Compensation
Committee (the “Performance Period”) for the Energy Transfer Compensation Committee to evaluate and determine an overall funded cash bonus pool
based on achievement of (i) an internal Adjusted EBITDA target (“Adjusted EBITDA Target”), (ii) an internal distributable cash flow target (“DCF
Target”) and (iii) performance of each department compared to the applicable departmental budget (“Departmental Budget Target”). For purposes of the
Adjusted EBITDA Target and the DCF Target established in the Bonus Plan, the measures of Adjusted EBITDA and Distributable Cash Flow were
calculated using the same definitions as used in the Partnership’s publicly reported financial information, including the Partnership’s earnings press
releases, investor presentations, and annual and quarterly filings on Forms 10-K and 10-Q. The performance criteria are weighted 60% on the achievement
of the Adjusted EBITDA Target, 20% on the achievement of the DCF Target and 20% on the achievement of the Departmental Budget Target (collectively,
“Budget Targets”). The total amount of cash to be allocated to the funded bonus pool will range from 0% to 120% for each of the budgeted DCF Target and
Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The maximum funding of the bonus pool is 116% of the
total pool target and to achieve such funding each of the Adjusted EBITDA and the DCF Target must achieve 120% funding and the Department Budget
target must achieve its 100% target. While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance
under the Adjusted EBITDA Target is below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash
award for the Performance Period based upon the level of attainment of the Budget Targets and his or her individual performance. Awards are paid in cash
as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the Performance Period.
Under the Amended Bonus Plan, for each Performance Period after January 1, 2023, the Energy Transfer Compensation Committee will evaluate and
determine an overall funded cash bonus pool based on achievement of (i) an Adjusted EBITDA
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Target, (ii) a DCF Target and (iii) a Departmental Budget Target. Under the Amended Bonus Plan, the Budget Targets were weighted 60% on the
achievement of the Adjusted EBITDA Target, 25% on the achievement of the DCF Target and 15% on the achievement of the Departmental Budget Target.
Under the Amended Bonus Plan, the DCF Target weighting increased to 25% from 20% under the Bonus and the Budget Target weighting was reduced
from 20% to 15%. The total amount of cash to be allocated to the funded bonus pool will range from 0% to 135% for each of the budgeted DCF Target and
Adjusted EBITDA Target and will range from 0% to 100% of the Departmental Budget Target. The increased range on the funded bonus pool to 135% of
the budgeted DCF Target and Adjusted EBITDA Target under the Amended Bonus Plan represented an increase from 120% each under the Bonus Plan.
The maximum funding of the bonus pool of 130% of the total pool target under the Amended Bonus Plan is an increase from 116% under the Bonus Plan.
Maximum funding of the Adjusted EBITDA and the DCF Target under the Amended Bonus Plan requires achievement of 110% of the target as opposed to
120% under the Bonus Plan. The maximum funding of the Amended Bonus Plan at 130% is an increase from the 116% maximum under the Bonus Plan.
While the funded bonus pool will reflect an aggregation of performance under each target, in the event performance under the Adjusted EBITDA Target is
below 80% of its target, no bonus pool will be funded. If the bonus pool is funded, a participant may earn a cash award for the Performance Period based
upon the level of attainment of the Budget Targets and his or her individual performance. Awards under both the Bonus Plan and the Amended Bonus Plan
are paid in cash as soon as practicable after the end of the Performance Period but in no event later than two and one-half months after the end of the
Performance Period.
While the achievement of the Budget Targets sets a bonus pool under the Bonus Plan and the Amended Bonus Plan, actual bonus awards are discretionary.
These discretionary bonuses, if awarded, are intended to reward our named executive officers for the achievement of the Budget Targets during the
Performance Period in light of the contribution of each individual to our profitability and success during such year. The Energy Transfer Compensation
Committee also considers the recommendation of Mr. Warren in determining the specific annual cash bonus amounts for each of the named executive
officers. The Energy Transfer Compensation Committee does not establish its own financial performance objectives in advance for purposes of determining
whether to approve any annual bonuses, and it does not utilize any formulaic approach to determine annual bonuses.
For Messrs. McCrea and Long, their 2023 bonus pool targets were 160% of their respective annual base earnings, consistent with their previous 2022
targets. For 2023, the Energy Transfer Compensation Committee approved short-term annual cash bonus pool targets for Messrs. Whitehurst, Bramhall,
Mason and Wright of 130% of their respective annual base earnings, consistent with their previous 2022 targets.
In February 2024, the Energy Transfer Compensation Committee certified 2023 performance results under the Amended Bonus Plan and authorized
payment of 100% of the targeted pool. This bonus payout reflected the achievement of 100.9% of the Adjusted EBITDA Target, 99.7% of the DCF Target
and 99.7% of, or $28 million under, the Department Budget Target.
Based on the approved results, the Energy Transfer Compensation Committee approved a cash bonus relating to the 2023 calendar year to Messrs. McCrea,
Long, Bramhall, Whitehurst, Mason and Wright in the amounts of $2,300,000, $2,300,000, $825,000, $800,000, $840,000 and $775,000, respectively.
Equity Awards. Energy Transfer maintains and operates (i) the Second Amended and Restated Energy Transfer LP 2008 Incentive Plan (the “2008
Incentive Plan”); (ii) the Energy Transfer LP 2011 Long-Term Incentive Plan (the “2011 Incentive Plan”); the (iii) Energy Transfer LP 2015 Long-Term
Incentive Plan (the “2015 Plan”); (iv) the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (the “Energy Transfer Plan,” together with
the 2008 Incentive Plan, the 2011 Incentive Plan and the 2015 Plan, the “Energy Transfer Incentive Plans”). The Energy Transfer Incentive Plans authorize
the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, under each respective plan of RSUs upon such terms and
conditions as it may determine appropriate and in accordance with general guidelines as defined by the Energy Transfer Incentive Plans. Energy Transfer
has generally used time-vested restricted units and/or phantom units as the vehicle for its annual equity awards to eligible employees, including the named
executive officers.
In addition, in 2020, Energy Transfer adopted the Energy Transfer LP Long-Term Cash Restricted Unit Plan (the “CRU Plan”). The CRU Plan authorizes
the Energy Transfer Compensation Committee, in its discretion, to grant awards, as applicable, of CRSUs, upon such terms and conditions as it may
determine appropriate and in accordance with general guidelines as defined by the CRU Plan. Like awards from the Energy Transfer Incentive Plans,
awards from the CRU Plan will be used to incentivize and reward eligible employees over a long-term basis, and the CRU Plan is included for purposes of
these discussions as an “Energy Transfer Incentive Plan.”
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For 2023, the Energy Transfer Compensation Committee established long-term incentive targets for Messrs. McCrea and Long of 900% of their annual
base earnings, consistent with their previous targets. For 2023, the Energy Transfer Compensation Committee approved long-term incentive targets for
Messrs. Bramhall, Whitehurst, Mason and Wright of 500%, 500%, 500% and 500%, respectively, of their respective annual base earnings, consistent with
their previous targets.
The annual long-term incentive targets are used as the basis to determine the target number of units to be awarded to the eligible participant, including the
named executive officers. A multiple of base salary is used to set the pool target, that number is then divided by a weighted average price determined by
considering Energy Transfer’s modified total unitholder return (“TUR”) performance as measured against the average return of Energy Transfer’s identified
peer group over defined time periods. The modified TUR is designed to create a recognition of a performance adjustment to the equity awards based on the
prior periods measured to add an element of performance impact in setting grant date value even though the RSUs and CRSUs themselves are time-vested
vehicles. For purposes of establishing an initial price, Energy Transfer utilizes a 60 trading-day trailing weighted average price of Energy Transfer common
units prior to November 1 of the respective year. This average trading price is then subject to adjustment when Energy Transfer’s TUR is more than 5%
greater or less than that of its identified peer group. If the TUR analysis yields a result that is within 5% of its identified peer group, the Energy Transfer
Compensation Committee will simply use the 60 trading day trailing weighted average price divided by the applicable salary multiple to establish a target
pool for each eligible participant, including the named executive officers. If Energy Transfer’s TUR is outside of the 5% deviation, the 60 trading day
trailing weighted average will be adjusted up or down to a maximum of 15% from the trailing weighted average price based on Energy Transfer’s
performance as compared to the identified group. For 2022, the peer group included the following:
• Enterprise Products Partners, L.P.
• The Williams Companies, Inc.
• Kinder Morgan, Inc.
• Plains All American Pipeline, L.P.
• MPLX LP
For 2023, the Partnership’s TUR outperformed the identified peer group by approximately 6% based on the average of the identified comparison periods.
Consequently, the 2023 long-term incentive base price was decreased to increase the total available restricted pool by approximately 6%.
In December 2023, the Energy Transfer Compensation Committee in consultation with Mr. Warren approved grants of RSUs to Messrs. McCrea, Long,
Bramhall, Whitehurst, Mason and Wright of 782,138 units, 782,138 units, 189,750 units, 187,500 units, 187,500 units, and 170,775 units, respectively. The
Energy Transfer Compensation Committee also approved grants of CRSUs to Messrs. McCrea, Long, Bramhall, Whitehurst, Mason and Wright of 260,712
units, 260,712 units, 63,250 units, 62,500 units, 62,500 units and 56,925 units, respectively.
The RSUs granted in 2023 provide for incremental vesting over a five-year period, with 60% vesting at the end of the third year and the remaining 40%
vesting at the end of the fifth year. Vesting of the awards is generally subject to continued employment through each specified vesting date. The RSU
awards entitle the recipients to receive, with respect to each Energy Transfer unit subject to such award that has not either vested or been forfeited, a DER
cash payment promptly following each such distribution by Energy Transfer to its common unitholders.
The CRSUs granted in 2023 provide for incremental vesting over a three-year period, with 1/3 vesting at the end of each year. Each CRSU entitles the
award recipient to receive cash equal to the market value of one Energy Transfer common unit upon vesting. The CRSU do not include rights to DER cash
payments.
In approving the grant of such RSUs and CRSUs, including to the named executive officers, the Energy Transfer Compensation Committee considered
several factors, including the long-term objective of retaining such individuals as key drivers of Energy Transfer’s future success, the existing level of
equity ownership of such individuals and the previous awards to such individuals of equity awards subject to vesting. Vesting of the 2023 awards would
accelerate in the event of the death or disability of the recipient, including the named executive officers, or in the event of a change in control of Energy
Transfer as that term is defined under the Energy Transfer Incentive Plans.
As discussed below under “Potential Payments Upon a Termination or Change of Control,” all outstanding equity awards would automatically accelerate
upon a change in control event, which means vesting automatically accelerates upon a change of control irrespective of whether the officer is terminated. In
addition, the award agreements also include certain acceleration provisions upon retirement with the ability to accelerate 40% of outstanding unvested
awards under the Energy Transfer Incentive Plans at age 65 and 50% at age 68. These acceleration provisions require that the participant have not less than
five (5) years of employment service to the Partnership or an affiliate and are subject to the applicable provisions of IRC Section
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409(A), which may include a six (6) month delay in the vesting after retirement. Beginning in 2022, the retirement provision also requires that the award be
held for at least one year after the grant date in order to be eligible for acceleration.
We believe that permitting the accelerated vesting of equity awards upon a change in control creates an important retention tool for us by enabling
employees to realize value from these awards in the event that we undergo a change in control transaction. In addition, we believe permitting acceleration
of vesting upon a change in control creates a sense of stability in the course of transactions that could create uncertainty regarding their future employment
and encourage these officers to remain focused on their job responsibilities.
Affiliate and Subsidiary Equity Awards. In addition to his role as an officer for Energy Transfer during 2023, Mr. Bramhall has certain responsibilities for
Sunoco LP, including a leadership role for certain shared service functions. Notwithstanding such responsibilities beginning in 2023, 100% of Mr.
Bramhall’s compensation, including his long-term incentive awards, were attributable on to Energy Transfer.
Special One-Time Awards to Co-Chief Executive Officers. In recognition of their assumption of their new roles as Co-Chief Executive Officers effective
January 1, 2021, the Energy Transfer Compensation Committee approved certain one-time awards to Messrs. McCrea and Long.
Mr. McCrea received a special one-time award of 241,815 RSUs under the Energy Transfer Incentive Plans and a special cash payment of $1,625,000 in
connection with his appointment as Co-Chief Executive Officer, effective January 1, 2021.
Mr. Long received a special one-time award of 483,630 RSUs under the Energy Transfer Incentive Plans in connection with his appointment as Co-Chief
Executive Officer, effective January 1, 2021.
The RSU awards to Messrs. McCrea and Long were made at the same grant date valuation and vesting schedules used for the annual equity awards
described above under “—Equity Awards” section above. These awards were approved by the Energy Transfer Compensation Committee on December 30,
2020 to be effective immediately upon Messrs. McCrea and Long assuming their new roles on January 1, 2021 and are reflected as compensation in 2021
in the Compensation Tables section below.
Unit Ownership Guidelines. In 2021, the Board of Directors of our General Partner adopted an update to the Executive Unit Ownership Guidelines (the
“Guidelines”), which sets forth minimum ownership guidelines applicable to certain executives of Energy Transfer with respect to Energy Transfer and
Sunoco LP common units, as applicable. The applicable Guidelines are denominated as a multiple of base salary, and the amount of common units required
to be owned increases with the level of responsibility. Under these Guidelines, (i) the Chief Executive Officer/Co-Chief Executive Officer(s) are expected
to own common units having a minimum value of six times base salary; (ii) the Chief Operating Officer, the Chief Financial Officer, the General Counsel
and other C-Suite executives expected to own common units having a minimum value of four times their respective base salary; and (iii) Senior Vice
Presidents are expected to own common units having a minimum value of two times their respective base salary. In addition to the named executive
officers, these Guidelines also apply to other covered executives, which executives are expected to own either directly or indirectly in accordance with the
terms of the Guidelines, common units having minimum values ranging from one to four times their respective base salary.
The Energy Transfer Compensation Committee believes that the ownership of Energy Transfer and/or Sunoco LP common units, as reflected in these
Guidelines, is an important means of tying the financial risks and rewards for its executives to Energy Transfer’s total unitholder return, aligning the
interests of such executives with those of Unitholders, and promoting Energy Transfer’s interest in good corporate governance.
Covered executives are generally required to achieve their ownership level within five years of becoming subject to the Guidelines. As of December 31,
2023, all of the named executive officers were compliant with the level required of the Guidelines as of that date.
Covered executives may satisfy the Guidelines through direct ownership of Energy Transfer and/or Sunoco LP common units or indirect ownership by
certain immediate family members. Direct or indirect ownership of Energy Transfer and/or Sunoco LP common units shall count on a one-to-one ratio for
purposes of satisfying minimum ownership requirements; however, unvested unit awards may not be used to satisfy the minimum ownership requirements.
Executive officers, including the named executive officers, who have not yet met their respective guideline must retain and hold all common units (less
common units sold to cover the executive’s applicable taxes and withholding obligation) received in connection with long-term incentive awards. Once the
required ownership level is achieved, ownership of the required common units must be maintained for as long as the covered executive is subject to the
Guidelines. However, those individuals who have met or exceeded their applicable ownership level guideline may dispose of the common units in a manner
consistent with
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applicable laws, rules and regulations, including regulations of the SEC and our internal policies, but only to the extent that such individual’s remaining
ownership of common units would continue to exceed the applicable ownership level.
Qualified Retirement Plan Benefits. The Energy Transfer LP 401(k) Plan (the “Energy Transfer 401(k) Plan”) is a defined contribution 401(k) plan, which
covers substantially all of our employees, including the named executive officers. Employees may elect to defer up to 100% of their eligible compensation
after applicable taxes, as limited under the Internal Revenue Code. We make a matching contribution that is not less than the aggregate amount of matching
contributions that would be credited to a participant’s account based on a rate of match equal to 100% of each participant’s elective deferrals up to 5% of
covered compensation. The amounts deferred by the participant are fully vested at all times, and the amounts contributed by the Partnership become vested
based on years of service. We provide this benefit as a means to incentivize employees and provide them with an opportunity to save for their retirement.
The Partnership provides a 3% profit sharing contribution to employee 401(k) accounts for all employees with a base compensation below a specified
threshold. The contribution is in addition to the 401(k) matching contribution and employees become vested based on years of service.
Health and Welfare Benefits. All full-time employees, including our named executive officers may participate in the Partnership’s health and welfare
benefit programs including medical, dental, vision, flexible spending, life insurance and disability insurance.
Termination Benefits. Our named executive officers do not have any employment agreements that call for payments of termination or severance benefits or
that provide for any payments in the event of a change in control of our General Partner; however, the award agreement to the named executive officers
under the Energy Transfer Incentive Plans, the 2018 Sunoco LP Plan and the Sunoco LP 2012 Long-Term Incentive Plan (the “2012 Sunoco LP Plan”)
provide for immediate vesting of all unvested restricted unit awards in the event of a (i) change of control, as defined in the plan; (ii) death or (iii) disability,
as defined in the applicable plan. Please refer to “Compensation Tables - Potential Payments Upon a Termination or Change of Control” for additional
information.
In addition, in 2021 the Partnership has also adopted the Partnership Severance Plan and Summary Plan Description (the “Severance Plan”), which
provides for payment of certain severance benefits in the event of Qualifying Termination (as that term is defined in the Severance Plan). In general, the
Severance Plan provides payment of two weeks of annual base salary for each year or partial year of employment service up to a maximum of fifty-two
weeks or one year of annual base salary (with a minimum of four weeks of annual base salary) and up to three months of continued group health insurance
coverage. The Severance Plan also provides that we may determine to pay benefits in addition to those provided under the Severance Plan based on special
circumstances, which additional benefits shall be unique and non-precedent setting. The Severance Plan is available to all salaried employees on a
nondiscriminatory basis; therefore, amounts that would be payable to our named executive officers upon a Qualified Termination have been excluded from
“Compensation Tables – Potential Payments Upon a Termination or Change of Control” below.
Energy Transfer LP Non-Qualified Deferred Compensation Plan (the “Energy Transfer NQDC Plan”) is a deferred compensation plan, which permits
eligible highly compensated employees to defer a portion of their salary, bonus, and/or quarterly non-vested phantom unit distribution equivalent income
until retirement, termination of employment or other designated distribution event. Each year under the Energy Transfer NQDC Plan, eligible employees
are permitted to make an irrevocable election to defer up to 50% of their annual base salary, 50% of their quarterly non-vested phantom unit distribution
income, and/or 50% of their discretionary performance bonus compensation during the following year. Pursuant to the Energy Transfer NQDC Plan,
Energy Transfer may make annual discretionary matching contributions to participants’ accounts; however, Energy Transfer has not made any discretionary
contributions to participants’ accounts and currently has no plans to make any discretionary contributions to participants’ accounts. All amounts credited
under the Energy Transfer NQDC Plan (other than discretionary credits) are immediately 100% vested. Participant accounts are credited with deemed
earnings or losses based on hypothetical investment fund choices made by the participants among available funds.
Participants may elect to have their account balances distributed in one lump sum payment or in annual installments over a period of three or five years
upon retirement, and in a lump sum upon other termination events. Participants may also elect to take lump-sum in-service withdrawals five years or longer
in the future, and such scheduled in-service withdrawals may be further deferred prior to the withdrawal date. Upon a change in control (as defined in the
Energy Transfer NQDC Plan) of Energy Transfer, all Energy Transfer NQDC Plan accounts are immediately vested in full. However, distributions are not
accelerated and, instead, are made in accordance with the Energy Transfer NQDC Plan’s normal distribution provisions unless a participant has elected to
receive a change of control distribution pursuant to his deferral agreement.
Risk Assessment Related to our Compensation Structure. We believe that the compensation plans and programs for our named executive officers, as well as
our other employees, are appropriately structured and are not reasonably likely to result in material
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risk to us. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could harm our
value or reward poor judgment. We also believe we have allocated compensation among base salary and short and long-term compensation in such a way
as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for executive officers and other employees
significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the
financial performance of a portion of our operations. Our subsidiaries generally determine whether, and to what extent, their respective named executive
officers receive a cash bonus based on achievement of specified financial performance objectives as well as the individual contributions of our named
executive officers to the Partnership’s success. We and our subsidiaries use restricted units and phantom units rather than unit options for equity awards
because restricted units and phantom units retain value even in a depressed market so that employees are less likely to take unreasonable risks to get, or
keep, options “in-the-money.” Finally, the time-based vesting over five years for our long-term incentive awards ensures that the interests of employees
align with those of Unitholders and our subsidiaries’ unitholders for our long-term performance.
Tax and Accounting Implications of Equity-Based Compensation Arrangements
Deductibility of Executive Compensation
We are a limited partnership and not a corporation for United States federal income tax purposes. Therefore, we believe that the compensation paid to the
named executive officers is not subject to the deduction limitations under Section 162(m) of the Internal Revenue Code and therefore is generally fully
deductible for United States federal income tax purposes.
Accounting for Non-Cash Compensation
For non-cash compensation arrangements, we record compensation expense over the vesting period of the awards, as discussed further in Note 2 and Note
9 to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
Compensation Committee Interlocks and Insider Participation
Mr. Steven R. Anderson and Mr. Michael K. Grimm are the only members of the Energy Transfer Compensation Committee. During 2023, no member of
the Energy Transfer Compensation Committee was an officer or employee of us or any of our subsidiaries or served as an officer of any company with
respect to which any of our executive officers served on such company’s board of directors. Mr. Grimm is not a former employee of ours or any of our
subsidiaries. Mr. Anderson was previously an employee of the Partnership until his retirement in October 2009, as discussed in his biographical
information included in “Item 10. Directors, Executive Officers and Corporate Governance.”
Report of Compensation Committee
The board of directors of our General Partner has reviewed and discussed the section entitled “Compensation Discussion and Analysis” with the
management of Energy Transfer. Based on this review and discussion, we have recommended that the Compensation Discussion and Analysis be included
in this annual report on Form 10-K.
The Compensation Committee of the
Board of Directors of LE GP, LLC,
general partner of Energy Transfer LP
Steven R. Anderson
Michael K. Grimm
The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this annual report on Form 10-K into any
filing under the Securities Act of 1933, as amended, or the Exchange Act, except to the extent that we specifically incorporate this information by
reference, and shall not otherwise be deemed filed under those Acts.
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Index to Financial Statements
Compensation Tables
Summary Compensation Table
Name and Principal Position
Thomas E. Long
Co-Chief Executive Officer
Marshall S. (Mackie) McCrea, III
Co-Chief Executive Officer
(4)
Dylan A. Bramhall
Group Chief Financial Officer
Bradford D. Whitehurst
Executive Vice President – Tax and
Corporate Initiatives
Thomas P. Mason
Executive Vice President – Alternative
Energy and President – LNG
James M. Wright, Jr.
Executive Vice President, General
Counsel and Chief Compliance
Officer
Year
2023
2022
2021
2023
2022
2021
2023
2022
2023
2022
2021
2023
2022
2021
2023
2022
Salary
($)
Bonus
($)
Equity
Awards
($)
(1)
Non-Equity
Incentive Plan
(2)
Compensation
($)
Change in
Pension
Value and
Nonqualified
Deferred
Compensation
Earnings ($)
All Other
Compensation
($)
(3)
Total
($)
$
1,432,554 $
— $
13,282,060 $
2,300,000 $
— $
25,167 $
17,039,781
1,372,410
1,322,750
1,432,554
1,372,410
1,322,750
594,406
429,808
670,845
628,125
605,413
711,980
666,595
642,445
563,063
488,808
—
—
—
1,600,000
3,225,000
—
—
—
—
—
—
—
—
—
—
14,344,161
15,224,039
13,282,060
14,344,161
13,734,458
3,222,286
3,241,514
3,184,077
3,646,060
3,102,694
3,184,077
3,870,995
3,279,498
2,900,058
1,963,263
2,635,027
3,156,400
2,300,000
2,635,027
3,156,400
825,000
700,000
800,000
950,000
1,174,000
840,000
1,040,900
1,252,000
775,000
762,540
—
—
—
—
—
—
—
—
—
—
—
—
—
13,991
18,550
23,917
27,014
24,044
22,794
22,044
17,760
16,298
19,760
18,510
15,760
23,167
21,917
22,706
90,391
19,120
18,375,515
19,730,203
17,038,658
19,974,392
21,460,652
4,659,452
4,387,620
4,674,682
5,242,695
4,897,867
4,759,224
5,600,407
5,196,649
4,342,503
3,252,281
(1)
(2)
(3)
(4)
Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB
ASC Topic 718, disregarding any estimates for forfeitures. For Messrs. Bramhall and Whitehurst amounts for one or more periods include equity
awards of our subsidiary, Sunoco LP, as reflected in the “Grants of Plan-Based Awards Table.” See Note 9 to our consolidated financial statements
included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity awards. Although
the CRSU awards may only be settled in cash, they are based upon the value of Energy Transfer common units and are accounted for as equity awards
within these compensation tables.
Energy Transfer maintains the Bonus Plan which provides for discretionary bonuses. Awards of discretionary bonuses are tied to achievement of
targeted performance objectives and described in the Compensation Discussion and Analysis.
The amounts reflected for 2023 in this column include (i) matching contributions to the Energy Transfer 401(k) Plan made on behalf of the named
executive officers of $16,500 each for Messrs. Long, McCrea, Bramhall, Whitehurst, Mason and Wright, and (ii) health savings account contributions
made on behalf of the named executive officers of $2,000 each for Messrs. Long, McCrea, Whitehurst and Wright, (iii) the dollar value of life
insurance premiums paid for the benefit of the named executive officers, and (iv) $68,279 in relocation costs for Mr. Wright. The amounts reflected for
all periods exclude distribution payments in connection with distribution equivalent rights on unvested unit awards, because the dollar value of such
distributions are factored into the grant date fair value reported in the “Equity Awards” column of the Summary Compensation Table at the time that
the unit awards and distribution equivalent rights were originally granted. For 2023, distribution payments in connection with distribution equivalent
rights totaled $3,762,597 for Mr. Long, $4,425,772 for Mr. McCrea, $625,571 for Mr. Bramhall, $1,121,545 for Mr. Whitehurst, $1,180,863 for Mr.
Mason, and $531,209 for Mr. Wright; these amounts include distribution payments on Sunoco LP unit awards for those executives with such unvested
awards.
The amounts reflected in the bonus column for Mr. McCrea in 2022 and 2021 include $1,600,000 per year paid in connection with a time-vested cash
award granted in 2020, which represented 50% of Mr. McCrea’s total equity award target for that year; no additional amounts remain outstanding
under that award. The amount reflected in the bonus column for 2021 for Mr. McCrea also includes the vesting and payment on February 1, 2021 of a
one-time, time-vested cash award of $1,625,000 to Mr. McCrea, which was originally granted in October 2020 in connection with Mr. McCrea’s
assumption of his role as Co-Chief Executive Officer.
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Index to Financial Statements
Grants of Plan-Based Awards in 2023
Name
Energy Transfer Unit Awards:
Thomas E. Long
Marshal S. (Mackie) McCrea, III
Dylan A. Bramhall
Bradford D. Whitehurst
Thomas P. Mason
James M. Wright, Jr.
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long
Marshal S. (Mackie) McCrea, III
Dylan A. Bramhall
Bradford D. Whitehurst
Thomas P. Mason
James M. Wright, Jr.
Grant Date
12/8/2023
12/8/2023
12/8/2023
12/8/2023
12/8/2023
12/8/2023
12/8/2023
12/8/2023
12/8/2023
12/8/2023
12/8/2023
12/8/2023
All Other Unit Awards: Number
of Units
(#)
Grant Date Fair Value of Unit
Awards
(1)
$
782,138
782,138
189,750
187,500
187,500
170,775
260,712
260,712
63,250
62,500
62,500
56,925
10,402,435
10,402,435
2,523,675
2,493,750
2,493,750
2,271,308
2,879,625
2,879,625
698,611
690,327
690,327
628,750
(1)
We have computed the grant date fair value of unit awards in accordance with FASB ASC Topic 718, as further described above and in Note 9 to our
consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.” For Energy Transfer cash restricted unit awards,
the grant date fair value is discounted for the expected distribution yield during the vesting period, as those awards do not include distribution
equivalent rights.
Narrative Disclosure to Summary Compensation Table and Grants of the Plan-Based Awards Table
A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, and
401(k) plan contributions can be found in the Compensation Discussion and Analysis that precedes these tables.
Outstanding Equity Awards at 2023 Fiscal Year-End
Name
Energy Transfer Unit Awards:
Thomas E. Long
Marshal S. (Mackie) McCrea, III
Dylan A. Bramhall
Bradford D. Whitehurst
Grant Date
(1)
Number of Units That Have Not Vested
(#)
(2)
Market or Payout Value of Units That
Have Not Vested
($)
(3)
Unit Awards
(1)
12/8/2023
12/12/2022
12/16/2021
12/30/2020
12/16/2019
12/8/2023
12/12/2022
12/16/2021
12/30/2020
12/16/2019
12/8/2023
12/12/2022
12/16/2021
12/30/2020
12/16/2019
12/8/2023
12/12/2022
12/16/2021
12/30/2020
12/16/2019
152
$
782,138
958,950
1,121,250
264,872
86,000
782,138
958,950
1,121,250
395,266
272,960
189,750
175,125
83,400
15,000
21,000
187,500
243,750
228,000
66,640
60,920
10,793,504
13,233,510
15,473,250
3,655,234
1,186,800
10,793,504
13,233,510
15,473,250
5,454,671
3,766,848
2,618,550
2,416,725
1,150,920
207,000
289,800
2,587,500
3,363,750
3,146,400
919,632
840,696
Table of Contents
Index to Financial Statements
Thomas P. Mason
James M. Wright, Jr.
Energy Transfer Cash Restricted Unit
Awards:
Thomas E. Long
Marshal S. (Mackie) McCrea, III
Dylan A. Bramhall
Bradford D. Whitehurst
Thomas P. Mason
James M. Wright, Jr.
Sunoco LP Unit Awards:
Thomas E. Long
Dylan A. Bramhall
Bradford D. Whitehurst
12/8/2023
12/12/2022
12/16/2021
12/30/2020
12/16/2019
12/8/2023
12/12/2022
12/16/2021
12/30/2020
12/16/2019
12/8/2023
12/12/2022
12/16/2021
12/8/2023
12/12/2022
12/16/2021
12/8/2023
12/12/2022
12/16/2021
12/8/2023
12/12/2022
12/16/2021
12/8/2023
12/12/2022
12/16/2021
12/8/2023
12/12/2022
12/16/2021
12/30/2020
12/16/2019
12/12/2022
12/16/2021
12/30/2020
10/27/2020
12/16/2021
12/30/2020
12/16/2019
187,500
258,788
300,300
93,960
85,920
170,775
131,250
131,944
39,502
36,120
260,712
213,100
124,584
260,712
213,100
124,584
63,250
38,917
9,267
62,500
54,167
25,334
62,500
57,508
33,367
56,925
29,167
14,661
11,120
7,800
14,200
13,000
6,400
8,000
16,100
10,400
7,280
2,587,500
3,571,274
4,144,140
1,296,648
1,185,696
2,356,695
1,811,250
1,820,827
545,128
498,456
3,004,546
2,568,488
1,570,643
3,004,546
2,455,847
1,501,607
728,918
469,061
116,830
720,274
652,869
319,389
720,274
693,142
420,662
656,026
351,549
184,833
666,422
467,454
851,006
779,090
383,552
479,440
964,873
623,272
436,290
(1)
(2)
Certain of these outstanding awards represent subsidiary awards that converted into Energy Transfer awards upon the in connection with restructuring
transactions in prior periods.
Energy Transfer and Sunoco LP unit awards outstanding vest as follows:
•
•
•
•
•
at a rate of 60% in December 2026 and 40% in December 2028 for awards granted in December 2023;
at a rate of 60% in December 2025 and 40% in December 2027 for awards granted in December 2022;
at a rate of 60% in December 2024 and 40% in December 2026 for awards granted in December 2021;
100% in December 2025 for the remaining outstanding portion awards granted in October and December 2020; and
100% in December 2024 for the remaining outstanding portion of awards granted in December 2019.
Such awards may be settled at the election of the Energy Transfer Compensation Committee in (i) common units of Energy Transfer (subject to the
approval of the Energy Transfer Incentive Plans prior to the first vesting date by a majority of Unitholders pursuant to the rules of the New York Stock
Exchange); (ii) cash equal to the Fair Market Value (as such term is defined in the Energy Transfer Incentive Plans) of the Energy Transfer common
units that would otherwise be delivered
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Index to Financial Statements
pursuant to the terms of each named executive officers grant agreement; or (iii) other securities or property in an amount equal to the Fair Market
Value of Energy Transfer common units that would otherwise be delivered pursuant to the terms of the grant agreement, or a combination thereof as
determined by the Energy Transfer Compensation Committee in its discretion.
Energy Transfer cash restricted unit awards granted in December 2023 vest 1/3 per year in December 2024, 2025 and 2026. Energy Transfer cash
restricted unit awards granted in December 2022 vest 1/2 per year in December 2024 and 2025. The remaining outstanding Energy Transfer cash
restricted unit awards granted in December 2021 vest in December 2024.
(3)
Market value was computed as the number of unvested awards as of December 31, 2023 multiplied by the closing price of respective common units of
Energy Transfer and Sunoco LP. For Energy Transfer cash restricted unit awards, the grant date fair value is discounted for the expected distribution
yield during the vesting period, as those awards do not include distribution equivalent rights.
Units Vested in 2023
Name
Energy Transfer Unit Awards:
Thomas E. Long
Marshall S. (Mackie) McCrea, III
Dylan A. Bramhall
Bradford D. Whitehurst
Thomas P. Mason
James M. Wright, Jr.
Energy Transfer Cash Restricted Unit Awards:
Thomas E. Long
Marshall S. (Mackie) McCrea, III
Dylan A. Bramhall
Bradford D. Whitehurst
Thomas P. Mason
James M. Wright, Jr.
Sunoco LP Unit Awards:
Thomas E. Long
Dylan A. Bramhall
Bradford D. Whitehurst
Unit Awards
Number of Units
Acquired on Vesting
(#)
Value Realized on Vesting
($)
(1)
$
497,978
835,195
40,500
154,036
217,196
91,313
290,650
231,133
41,225
107,950
140,421
62,162
24,410
21,600
23,258
6,852,177
11,492,283
557,280
2,119,535
2,988,617
1,256,467
3,999,344
3,180,390
567,261
1,485,397
1,932,193
855,349
1,293,242
1,144,368
1,232,209
(1)
Amounts presented represent the value realized upon vesting of these awards, which is calculated as the number of units vested multiplied by the
applicable closing market price of applicable common units upon the vesting date.
We have not issued option awards.
Nonqualified Deferred Compensation Table
A description of the key provisions of the Partnership’s deferred compensation plan can be found in the compensation discussion and analysis above.
Name
James M. Wright, Jr.
Executive Contributions in
Last FY ($)
Acquired on Vesting
(#)
Registrant Contributions in
Last FY ($)
($)
(1)
Aggregate Earnings in Last
FY ($)
(1)
Aggregate
Withdrawals/Distributions
($)
Aggregate Balance at Last
FYE ($)
—
—
13,991
—
83,736
(1)
Amounts included in the aggregate earnings column above have been included in the change in non-qualified deferred compensation earnings column
of the summary compensation table.
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Index to Financial Statements
Potential Payments Upon a Termination or Change of Control
Equity Awards. As discussed in our Compensation Discussion and Analysis above, any unvested equity awards (including cash restricted unit awards)
granted pursuant the Energy Transfer Incentive Plans will automatically become vested upon a change of control, which is generally defined as the
occurrence of one or more of the following events: (i) any person or group becomes the beneficial owner of 50% or more of the voting power or voting
securities of Energy Transfer or its general partner; (ii) LE GP, LLC or an affiliate of LE GP, LLC ceases to be the general partner of Energy Transfer; or
(iii) the sale or other disposition, including by liquidation or dissolution, of all or substantially all of the assets of Energy Transfer in one or more
transactions to anyone other than an affiliate of Energy Transfer.
In addition, as explained in Equity Awards section of our Compensation Discussion and Analysis above, the restricted unit awards, phantom unit awards
and cash restricted unit awards under the Energy Transfer Incentive Plans, the Sunoco LP Plan and the 2012 Sunoco LP Plan generally require the
continued employment of the recipient during the vesting period, provided however, the unvested awards will be accelerated in the event of the death or
disability of the award recipient prior to the applicable vesting period being satisfied. All awards outstanding to the named executive officers under the
Energy Transfer Incentive Plans, the 2018 Sunoco LP Plan or the 2012 Sunoco LP Plan would be accelerated in the event of a change in control of the
Partnership.
In addition, the Energy Transfer Compensation Committee and the compensation committee of the general partner of Sunoco LP, have approved a
retirement provision, which provides that employees, including the named executive officers with at least five years of service with the general partner,
who leave the respective general partner voluntarily due to retirement (i) after age 65 but prior to age 68 are eligible for accelerated vesting of 40% of his or
her award; or (ii) after 68 are eligible for accelerated vesting of 50% his or her award. The acceleration of the awards is subject to the applicable provisions
of IRC Section 409(A). Beginning with awards granted in 2022, the retirement provision also requires that the award be held for at least one year after the
grant date in order to be eligible for acceleration.
The following table shows the amount of incremental value that would have been received by each of the NEOs upon certain events of termination or a
change of control resulting in the accelerated vesting of the restricted units and/or restricted phantom units held by our NEOs on December 31, 2023:
Name
(2)
Thomas E. Long
Marshall S. (Mackie) McCrea, III
Dylan A. Bramhall
Bradford D. Whitehurst
Thomas P. Mason
James M. Wright, Jr.
(2)
(2)
Termination due to Death
or Disability ($)
(1)
Termination for Any
Other Reason ($)
Change of Control
with or without
Continued
Employment
($)
(1)
Not for Cause
Termination ($)
$
$
53,734,034
56,979,648
10,713,868
15,310,675
14,901,833
8,422,747
$
—
—
—
—
—
—
$
53,734,034
56,979,648
10,713,868
15,310,675
14,901,833
8,422,747
—
—
—
—
—
—
Benefit
Unit Vesting
Unit Vesting
Unit Vesting
Unit Vesting
Unit Vesting
Unit Vesting
(1)
(2)
The amounts reflected above represent the product of the number of RSUs and CRSUs units that were subject to vesting/restrictions on December 31,
2023 multiplied by the closing price of applicable common units on that date.
For Messrs. Long, Bramhall and Whitehurst, the amounts reported above include outstanding Energy Transfer plan-based awards and outstanding
Sunoco LP restricted units.
Deferred Compensation Plan. As discussed in our Compensation Discussion and Analysis above, all amounts under the Energy Transfer NQDC Plan (other
than discretionary credits) are immediately 100% vested. Upon a change of control (as defined in the Energy Transfer NQDC Plan), distributions from the
respective plan would be made in accordance with the normal distribution provisions of the respective plan. A change of control is generally defined in the
Energy Transfer NQDC Plan as any change of control event within the meaning of Treasury Regulation Section 1.409A-3(i)(5).
CEO Pay Ratio
In accordance with Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, set forth
below is information about the relationship of the annual total compensation of Messrs. Long and McCrea, Co-Chief Executive Officers, and the annual
total compensation of our employees.
For the 2023 calendar year, the annual total compensation of Messrs. Long and McCrea, as reported in the Summary Compensation Table of this Item 11
was $17,039,781 and $17,038,658, respectively.
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The median total compensation of the employees supporting the Partnership (other than Messrs. Long and McCrea) was $147,362 for 2023.
Based on this information, for 2023 the ratio of the annual total compensation of Messrs. Long and McCrea to the median of the annual total compensation
of the employees supporting the Partnership as of December 31, 2023 was approximately 116 to 1.
To identify the median of the annual total compensation of the employees supporting the Partnership, the following steps were taken:
1.
It was determined that, as of December 31, 2023, the applicable employee populations consisted of 10,579 with all of the identified individuals being
employed in the United States. This population consisted of all of our full-time and part-time employees. We did not engage any independent
contractors in 2023 that are required to be included in our employee population for the CEO pay ratio evaluation.
2. To identify the “median employee” from our employee population, we compared the total earnings of our employees as reflected in our payroll records
as reported on Form W-2 for 2023.
3. We identified our median employee using W-2 reporting and applied this compensation measure consistently to all of our employees required to be
included in the calculation. We did not make any cost of living adjustments in identifying the “median employee.”
4. Once we identified our median employee, we combined all elements of the employee’s compensation for 2023 resulting in an annual compensation of
$147,362 with total cash compensation of $126,264 The difference between such employee’s total earnings and the employee’s total compensation
represents the estimated value of the employee’s health care benefits (estimated for the employee and such employee’s eligible dependents at $13,908)
and the employee’s 401(k) matching contribution and profit sharing contribution (estimated at $7,190 per employee, includes $4,501 per employee on
average matching contribution and $2,689 per employee on average profit sharing contribution (employees earning over $175,000 in base are
ineligible for profit sharing)).
5. With respect to Messrs. Long and McCrea, we used the amount reported in the “Total” column of our 2023 Summary Compensation Table under this
Item 11.
Director Compensation
In 2023, the compensation arrangements for outside directors included a $100,000 annual retainer for services on the board. If a director served on the
Energy Transfer Audit Committee, such director would receive an annual cash retainer ($15,000 or $25,000 in the case of the chairman). If a director
served on the Energy Transfer Compensation Committee, such director would receive an annual cash retainer ($7,500 or $15,000 in the case of the
chairman). The fees for membership on the Conflicts Committee are determined on a per instance basis for each committee assignment.
The outside directors of our General Partner are also entitled to an annual restricted unit award under the Energy Transfer Incentive Plans equal to an
aggregate of $125,000 based on the same grant date valuation as is used for annual long-term incentive awards made to Partnership officers, including the
named executive officers, through the annual modified total unitholder return analysis. These Energy Transfer common units will vest 60% after the third
year and the remaining 40% after the fifth year after the grant date. The compensation expense recorded is based on the grant-date market value of the
Energy Transfer common units and is recognized over the vesting period. Distributions are paid during the vesting period.
The compensation paid to the non-employee directors of our General Partner in 2023 is reflected in the following table:
$
Name
(3)
Steven R. Anderson
Richard D. Brannon
Ray C. Davis
Michael K. Grimm
John W. McReynolds
James R. Perry
Matthew S. Ramsey
Fees Paid in Cash
($)
(1)
Unit Awards
($)
(2)
All Other Compensation
($)
Total
($)
$
122,500
125,000
25,000
130,000
100,000
100,000
100,000
$
137,162
137,162
—
137,162
137,162
137,162
137,162
$
—
—
—
—
—
—
—
259,662
262,162
25,000
267,162
237,162
237,162
237,162
(1)
(2)
Fees paid in cash are based on amounts paid during the period.
Equity award amounts reflect the aggregate grant date fair value of unit awards granted for the periods presented, computed in accordance with FASB
ASC Topic 718, disregarding any estimates for forfeitures. See Note 9 to our consolidated
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Index to Financial Statements
financial statements included in “Item 8. Financial Statements and Supplementary Data” for additional assumptions underlying the value of the equity
awards.
As discussed above, the number of units awarded is based on the annual award amount of $125,000 divided by the same grant-date valuation as is used
for annual long-term incentive award to Partnership officers through the modified total unitholders return analysis.
(3)
Mr. Davis resigned from the board of directors of our General Partner, effective December 31, 2022, the fess paid in cash in 2023 above relate to
services performed in 2022.
As of December 31, 2023, Mr. Anderson had 46,584 unvested Energy Transfer restricted units outstanding, Mr. Brannon had 46,584 unvested Energy
Transfer restricted units outstanding, Mr. Grimm had 46,584 unvested Energy Transfer restricted units outstanding, Mr. McReynolds had 24,172 unvested
Energy Transfer restricted units outstanding, Mr. Perry had 44,565 unvested Energy Transfer restricted units outstanding and Mr. Ramsey had 21,302
unvested Energy Transfer restricted units outstanding.
The executive chairman and the employee directors do not receive compensation for their service on the board of our General Partner.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER
MATTERS
Equity Compensation Plan Information
The following table sets forth in tabular format, a summary of our equity plan information as of December 31, 2023:
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)
Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)
— $
39,105,067
39,105,067 $
—
—
—
Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
—
42,904,968
42,904,968
Plan Category
Equity compensation plans approved by security holders
Equity compensation plans not approved by security
holders
Total
Energy Transfer LP Units
The following table sets forth certain information as of February 9, 2024, regarding the beneficial ownership of our voting securities by (i) certain
beneficial owners of more than 5% of our Common Units, (ii) each director and named executive officer
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Index to Financial Statements
of our General Partner and (iii) all current directors and executive officers of our General Partner as a group. The General Partner knows of no other person
not disclosed herein who beneficially owns more than 5% of our Common Units.
Name and Address of
(1)
Beneficial Owner
(4)
(6)
(5)
Kelcy L. Warren
Thomas E. Long
Marshall S. (Mackie) McCrea, III
Dylan A. Bramhall
Thomas P. Mason
Bradford D. Whitehurst
James M. Wright, Jr.
Steven R. Anderson
Richard D. Brannon
(9)
Michael K. Grimm
John W. McReynolds
James R. Perry
Matthew S. Ramsey
All Directors and Executive Officers as a group (14 persons)
(10)
(7)
(8)
Beneficially Owned
(2)
Percent of Class
Common Units
298,799,984
1,075,649
3,783,579
134,506
891,285
663,131
276,646
1,569,047
708,936
768,811
30,225,200
135,873
1,121,845
340,294,745
Class A
(3)
Units
833,543,364
—
—
—
—
—
—
—
—
—
—
—
—
833,543,364
Common Units
Class A Units
8.9 %
*
*
*
*
*
*
*
*
*
*
*
*
10.1 %
100.0 %
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
100.0 %
*
(1)
(2)
(3)
(4)
Less than 1%
The address for all listed beneficial owners is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.
Beneficial ownership for the purposes of this table is defined by Rule 13d-3 under the Exchange Act of 1934. Under that rule, a person is generally
considered to be the beneficial owner of a security if he has or shares the power to vote or direct the voting thereof or to dispose or direct the
disposition thereof or has the right to acquire either of those powers within sixty days. The nature of beneficial ownership for all listed persons is direct
with sole investment and disposition power unless otherwise noted. The beneficial ownership of each listed person is based on 3,367,757,556 common
units outstanding in the aggregate as of February 9, 2024.
The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common units and are not entitled to distributions and otherwise
have no economic attributes. The Energy Transfer Class A Units are not convertible into, or exchangeable for, Partnership common units. Under the
terms of the Energy Transfer Class A Units, upon the issuance by the Partnership of additional common units or any securities that have voting rights
that are pari passu with the Partnership common units, the Partnership will issue to the general partner additional Energy Transfer Class A Units such
that Mr. Warren, through his majority ownership of our general partner, maintains the approximately 20% voting percentage in the Partnership
represented by such Energy Transfer Class A Units equivalent to such Energy Transfer Class A Unit voting interest prior to such issuance of additional
common units. This provision of the Energy Transfer Class A Units shall terminate at such time as Mr. Warren ceases to be an officer or director of our
general partner, provided that all Energy Transfer Class A Units outstanding at such time shall be unchanged and remain outstanding. Mr. Warren’s
combined common unit and Energy Transfer Class A Unit ownership results in a voting interest in the Partnership of 27%.
Includes 120,385,650 common units held by Kelcy Warren Partners, L.P. and 10,224,429 common units held by Kelcy Warren Partners II, L.P., the
general partners of which are owned by Mr. Warren. Also includes 100,577,803 common units held by Kelcy Warren Partners III, LLC formerly
known as Seven Bridges Holdings, LLC, of which Mr. Warren is a member. Also includes 328,383 common units attributable to the interest of Mr.
Warren in ET Company Ltd and Three Dawaco, Inc., over which Mr. Warren exercises shared voting and dispositive power with Ray Davis. Also
includes 601,076 common units and 833,543,364 Energy Transfer Class A Units held by LE GP, LLC. Mr. Warren may be deemed to own common
units and Energy Transfer Class A Units held by LE GP, LLC due to his ownership of 81.2% of its member interests. Mr. Warren disclaims beneficial
ownership of common units and Energy Transfer Class A Units owned by LE GP, LLC other than to the extent of his interest in such entity. Also
includes 104,166 common units held by Mr. Warren’s spouse. Mr. Warren’s combined common unit and Energy Transfer Class A Unit ownership
results in a voting interest in the Partnership of 27%.
158
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Index to Financial Statements
(5)
(6)
(7)
(8)
(9)
(10)
Includes 45,389 common units held by a trust for the benefit of Mr. McCrea’s son, for which Mr. McCrea serves as trustee. Mr. McCrea disclaims
beneficial ownership of these units.
Includes 328,617 common units held by Mr. Whitehurst in a margin account.
Includes 1,544,558 common units held by Steven R. Anderson Revocable Trust, for which Mr. Anderson serves as trustee. Includes 603,100 common
units pledged as collateral for a line of credit.
Includes 580,000 common units held by B4 Capital Investments, LP, a limited partnership of which a limited liability company owned by Mr. Brannon
and his wife is the sole general partner and of which Mr. Brannon and his wife are the sole limited partners.
Includes 581,799 common units held Grimm Family Limited Partnership, a limited partnership of which a limited liability company owned by Mr.
Grimm is the sole general partner.
Includes 17,445,608 common units held by McReynolds Energy Partners L.P. and 12,142,593 common units held by McReynolds Equity Partners L.P.,
the general partners of which are owned by Mr. McReynolds. Mr. McReynolds disclaims beneficial ownership of common units owned by such limited
partnerships other than to the extent of his interest in such entities.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The Partnership’s principal sources of cash flow are derived from cash flows from the operations of its subsidiaries, including its direct and indirect
investments in the limited partner and general partner interests in Sunoco LP and USAC, both of which are limited partnerships engaged in energy-related
services.
In making its director independence determination, the Board considered business arrangements involving a director who owns equity interest in, and is the
CEO of, a company that owns working interests in oil and gas wells, and affiliates of the Partnership who made nominal payments to that company. None
of the arrangements involved payments to the company of more than $1 million in any of the past three fiscal years and the Board determined that the
relationship did not impact the director’s independence.
For a discussion of director independence, see “Item 10. Directors, Executive Officers and Corporate Governance.”
As a policy matter, our Conflicts Committee generally reviews any proposed related party transaction that may be material to the Partnership to determine
whether the transaction is fair and reasonable to the Partnership. The Partnership’s board of directors makes the determinations as to whether there exists a
related party transaction in the normal course of reviewing transactions for approval as the Partnership’s board of directors is advised by its management of
the parties involved in each material transaction as to which the board of directors’ approval is sought by the Partnership’s management. In addition, the
Partnership’s board of directors makes inquiries to independently ascertain whether related parties may have an interest in the proposed transaction. While
there are no written policies or procedures for the board of directors to follow in making these determinations, the Partnership’s board makes those
determinations in light of its contractually-limited fiduciary duties to the Unitholders. The Partnership Agreement of Energy Transfer provides that any
matter approved by the Conflicts Committee will be conclusively deemed to be fair and reasonable to Energy Transfer, approved by all the partners of
Energy Transfer and not a breach by the General Partner or its Board of Directors of any duties they may owe Energy Transfer or the Unitholders (see
“Risks Related to Conflicts of Interest” in “Item 1A. Risk Factors” in this annual report).
Additional information on our related party transactions is included in Note 2 to our consolidated financial statements included in “Item 8. Financial
Statements and Supplementary Data.”
159
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Index to Financial Statements
The following sets forth fees billed by Grant Thornton LLP for the audit of our annual financial statements and other services rendered (dollars in
millions):
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
(1)
Audit fees
Audit-related fees
(2)
Total
Years Ended December 31,
2022
2023
$
$
9.4 $
1.8
11.2 $
9.2
1.6
10.8
(1)
(2)
Includes fees for audits of annual financial statements of our companies, reviews of the related quarterly financial statements, and services that are
normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents
filed with the SEC and services related to the audit of our internal control over financial reporting.
Includes fees for audit-related services of subsidiary entities.
Pursuant to the charter of the Audit Committee, the Audit Committee is responsible for the oversight of our accounting, reporting and financial practices.
The Audit Committee has the responsibility to select, appoint, engage, oversee, retain, evaluate and terminate our external auditors; pre-approve all audit
and non-audit services to be provided, consistent with all applicable laws, to us by our external auditors; and establish the fees and other compensation to
be paid to our external auditors. The Audit Committee also oversees and directs our internal auditing program and reviews our internal controls.
The Audit Committee has adopted a policy for the pre-approval of audit and permitted non-audit services provided by our principal independent
accountants. The policy requires that all services provided by Grant Thornton LLP including audit services, audit-related services, tax services and other
services, must be pre-approved by the Audit Committee. All fees paid or expected to be paid to Grant Thornton LLP for fiscal years 2023 and 2022 were
pre-approved by the Audit Committee in accordance with this policy.
The Audit Committee reviews the external auditors’ proposed scope and approach as well as the performance of the external auditors. It also has direct
responsibility for and sole authority to resolve any disagreements between our management and our external auditors regarding financial reporting,
regularly reviews with the external auditors any problems or difficulties the auditors encountered in the course of their audit work, and, at least annually,
uses its reasonable efforts to obtain and review a report from the external auditors addressing the following (among other items):
•
•
•
•
•
the auditors’ internal quality-control procedures;
any material issues raised by the most recent internal quality-control review, or peer review, of the external auditors;
the independence of the external auditors;
the aggregate fees billed by our external auditors for each of the previous two years; and
the rotation of the lead partner.
160
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Index to Financial Statements
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as a part of this Report:
(1) Financial Statements – see Index to Financial Statements
(2) Financial Statement Schedules – None
(3) Exhibits – see Index to Exhibits
161
Page
F - 1
163
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Index to Financial Statements
None.
ITEM 16. FORM 10-K SUMMARY
162
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Index to Financial Statements
The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed
below, are not applicable.
INDEX TO EXHIBITS
Exhibit
Number Description
2.1
2.2
2.3
2.4
2.5
3.1
3.1.1
3.2
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
4.11
Agreement and Plan of Merger, dated as of September 15, 2019, by and among Energy Transfer LP, Nautilus Merger Sub LLC and
SemGroup Corporation (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed September 16, 2019)
Agreement and Plan of Merger, dated as of February 16, 2021, by and among Energy Transfer LP, Elk Merger Sub LLC, Elk GP Merger
Sub LLC, Enable Midstream Partners, LP, Enable GP, LLC, solely for the purpose of Section 21.(a)(i), LE GP, LLC, and, solely for the
purpose of Section 1.1(b)(i), CenterPoint Energy, Inc. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed
February 17, 2021)
Agreement and Plan of Merger, dated as of March 5, 2021, by and among Energy Transfer LP, ETO Merger Sub LLC and Energy Transfer
Operating, L.P. (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed March 5, 2021)
Agreement and Plan of Merger, dated as of April 1, 2021, by and among Energy Transfer Operating, L.P., Sunoco Logistics Partners
Operations L.P. and Sunoco Logistics Partners GP LLC (incorporated by reference to Exhibit 2.1 to Form 8-K (File No. 1-32740) filed
April 2, 2021)
Agreement and Plan of Merger, dated as of April 1, 2021, by and among Energy Transfer LP and Energy Transfer Operating, L.P.
(incorporated by reference to Exhibit 2.2 to Form 8-K (File No. 1-32740) filed April 2, 2021)
Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 to Form S-1 (File No. 333-
128097) filed September 2, 2005)
Certificate of Amendment to Certificate of Limited Partnership of Energy Transfer LP (incorporated by reference to Exhibit 3.1 to Form 8-
K (File No. 1-32740) filed October 19, 2018)
Fourth Amended and Restated Agreement of Limited Partnership of Energy Transfer LP, dated November 3, 2023 (incorporated by
reference to Exhibit 3.2 to Form 8-K (File No. 1-32740) filed November 6, 2023)
Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by
reference to Exhibit 4.1 to Form 8-K (File No. 1-32740) filed September 20, 2010)
Fourth Supplemental Indenture, dated December 2, 2013 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as
trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed December 2, 2013)
Fifth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed May 28, 2014)
Sixth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee
(incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 1-32740) filed May 28, 2014)
Seventh Supplemental Indenture, dated May 22, 2015 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee
(including form of the Notes) (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed May 22, 2015)
Eighth Supplemental Indenture dated October 18, 2017 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as
trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed October 18th, 2017)
Ninth Supplemental Indenture, dated as of March 25, 2019, between Energy Transfer LP and U.S. Bank National Association as trustee
(incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed March 27, 2019)
Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank,
National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-11727) filed January 19, 2005)
Fifth Supplemental Indenture dated as of October 23, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P, the
subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form
8-K (File No. 1-11727) filed October 25, 2006)
Sixth Supplemental Indenture dated March 28, 2008, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank National
Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File
No. 1-11727) filed March 31, 2008)
Ninth Supplemental Indenture, dated as of May 12, 2011, to the Indenture dated January 18, 2005, by and between Energy Transfer
Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by
reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed May 12, 2011)
163
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Index to Financial Statements
Exhibit
Number Description
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
4.25
4.26
4.27
4.28
4.29
Tenth Supplemental Indenture, dated as of January 17, 2012, to the Indenture dated January 18, 2005, by and between Energy Transfer
Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by
reference to Exhibit 4.2 to Form 8-K (File No. 1-11727) filed January 17, 2012)
Eleventh Supplemental Indenture dated as of January 22, 2013 by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank
National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form
8-K (File No. 1-11727) filed January 23, 2013)
Twelfth Supplemental Indenture, dated as of January 24, 2013, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank
National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form
8-K (File No. 1-11727) filed June 26, 2013)
Thirteenth Supplemental Indenture, dated as of September 19, 2013, by and between Energy Transfer Partners, L.P., as issuer, and U.S.
Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to
Form 8-K (File No. 1-11727) filed September 19, 2013)
Fourteenth Supplemental Indenture, dated as of March 12, 2015, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank
National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form
8-K (File No. 1-11727) filed March 12, 2015)
Fifteenth Supplemental Indenture, dated as of June 23, 2015, by and between Energy Transfer Partners, L.P., as issuer, and U.S. Bank
National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.3 to Form
8-K (File No. 1-11727) filed June 23, 2015)
Sixteenth Supplemental Indenture, dated as of January 17, 2017, between Energy Transfer Partners, L.P. and U.S. Bank National
Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File
No. 1-11727) filed January 17, 2017)
Seventeenth Supplemental Indenture, dated as of December 1, 2017, between Energy Transfer Partners, L.P. and U.S. Bank National
Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 10.8 to Form 8-K (File
No. 1-31219) filed December 6, 2017)
Second Supplemental Indenture, dated December 1, 2017, among Energy Transfer Partners, L.P., and U.S. Bank National Association, as
trustee (incorporated by reference to Exhibit 10.5 to Form 8-K (File No. 1-31219) filed December 6, 2017)
Indenture, dated as of May 15, 1994, between Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A.,
relating to Sunoco, Inc.’s 9.00% Debentures due 2024 (incorporated by reference to Exhibit 4.8 to Form 8-K (File No. 1-31219) filed
October 5, 2012)
First Supplemental Indenture, dated as of October 5, 2012, among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National
Association, as successor trustee to Citibank, N.A., to the Indenture, dated as of May 15, 1994 (incorporated by reference to Exhibit 4.9 to
Form 8-K (File No. 1-11727) filed October 5, 2012)
Sixteenth Supplemental Indenture, dated as of September 21, 2017, by and among Sunoco Logistics Partners Operations L.P., as issuer,
Energy Transfer Partners, L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit
4.4 to Form 8-K (File No. 1-31219) filed September 25, 2017)
Fifteenth Supplemental Indenture, dated as of September 21, 2017, by and among Sunoco Logistics Partners Operations L.P., as issuer,
Energy Transfer Partners, L.P., as guarantor, and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit
4.2 to Form 8-K (File No. 1-31219) filed September 25, 2017)
Third Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Sunoco Logistics Partners
Operations L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-31219)
filed December 15, 2017)
Eighteenth Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Sunoco Logistics
Partners Operations L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-
31219) filed December 15, 2017)
Tenth Supplemental Indenture, dated as of December 12, 2017, by and among Energy Transfer Partners, L.P., Regency Energy Finance
Corp., Sunoco Logistics Partners Operations L.P. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to
Exhibit 10.3 to Form 8-K (File No. 1-31219) filed December 15, 2017)
Second Supplemental Indenture, dated as of December 1, 2017, by and between Energy Transfer Partners, L.P. and U.S. Bank National
Association, as trustee (incorporated by reference to Exhibit 10.6 to Form 8-K (File No. 1-31219) filed December 6, 2017)
Indenture, dated as of June 8, 2018, among Energy Transfer Partners, L.P. as issuer, Sunoco Logistics Partners Operations L.P., as
guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-31219) filed
June 8, 2018)
164
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Index to Financial Statements
Exhibit
Number Description
4.30
4.31
4.32
4.33
4.34
4.35
4.36
4.37
4.38
4.39
4.40
4.41
4.42
4.43
4.44
4.45
4.46
4.47
First Supplemental Indenture, dated as of June 8, 2018, by and among Energy Transfer Partners, L.P., as issuer, the subsidiary guarantors
named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-31219)
filed June 8, 2018)
Second Supplemental Indenture, dated as of January 15, 2019, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary
guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No.
1-31219) filed January 15, 2019)
Third Supplemental Indenture, dated as of March 25, 2019, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary
guarantors named therein, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No.
1-31219) filed March 27, 2019)
Fourth Supplemental Indenture dated as of January 22, 2020, by and among Energy Transfer Operating, L.P., as issuer, the subsidiary
guarantors named therein, U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-
31219) filed January 22, 2020)
Fifth Supplemental Indenture, dated as of December 28, 2021, by and among Energy Transfer LP, Enable Midstream Partners, LP and U.S.
Bank National Association (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-32740) filed December 28, 2021)
Indenture, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, CenterPoint Energy Resources Corp., as guarantor, and
U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-36413) filed May 29, 2014)
First Supplemental Indenture, dated as of May 27, 2014, by and among Enable Midstream Partners, LP, as issuer, CenterPoint Energy
Resources Corp., as guarantor and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File
No. 1-36413) filed May 29, 2014)
Second Supplemental Indenture, dated as of March 9, 2017, by and among Enable Midstream Partners, LP, as issuer, CenterPoint Energy
Resources Corp., as guarantor and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File
No. 1-36413) filed March 9, 2017)
Third Supplemental Indenture, dated as of May 10, 2018, by and among Enable Midstream Partners, LP, as issuer, and U.S. Bank National
Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-36413) filed May 10, 2018)
Fourth Supplemental Indenture, dated as of September 13, 2019, by and among Enable Midstream Partners, LP, as issuer, and U.S. Bank
National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-36413) filed September 13, 2019)
Indenture, dated as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company and NBD Bank
(the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New
York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee (incorporated by reference to Exhibit 4(a)
to Form 10-Q (File No. 001-02921) filed May 15, 1999)
First Supplemental Indenture dated, as of March 29, 1999, among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line
Company and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National
Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as Trustee, including
a form of Guarantee by Panhandle Eastern Pipe Line Company of the obligations of CMS Panhandle Holding Company (incorporated by
reference to Exhibit 4(b) to Form 10-Q (File No. 001-02921) filed May 15, 1999)
Second Supplemental Indenture between Southern Union Company and The Bank of New York, N.A., as Trustee, dated as of October 23,
2006 (incorporated by reference to Exhibit 4.1 to Form 8-K/A (File No. 001-06407) filed October 24, 2006)
Third Supplemental Indenture, dated as of June 24, 2013, between Southern Union Company and The Bank of New York Mellon Trust
Company, N.A., as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 001-06407) filed June 26, 2013)
Form of Sixth Supplemental Indenture, dated as of June 12, 2008, between PEPL and The Bank of New York Trust Company, N.A. (now
known as The Bank of New York Mellon Trust Company, N.A.), as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No.
001-02921) filed June 11, 2008)
Form of Seventh Supplemental Indenture, to be dated as of June 2, 2009, between PEPL and The Bank of New York Mellon Trust
Company, N.A. (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 001-02921) filed May 28, 2009)
Supplemental Indenture No. 3, dated as of June 24, 2013 between Southern Union Company and The Bank of New York Mellon Trust
Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 001-06407) filed June 26, 2013)
Supplemental Indenture No. 4, dated as of June 24, 2013, between Southern Union Company and The Bank of New York Mellon Trust
Company, N.A., as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 001-06407) filed June 26, 2013)
165
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Index to Financial Statements
Exhibit
Number Description
4.48
4.49
4.50
4.51
4.52
4.53
4.54
4.55
4.56
4.57
4.58
4.59
4.60
4.61
4.62
4.63
4.64
4.65
Third Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association
(incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed April 2, 2021)
Fourth Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association
(incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed April 2, 2021)
Fifth Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association
(incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-32740) filed April 2, 2021)
Seventeenth Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association
(incorporated by reference to Exhibit 10.4 to Form 8-K (File No. 1-32740) filed April 2, 2021)
Nineteenth Supplemental Indenture, dated as of April 1, 2021 by and between Energy Transfer LP and U.S. Bank National Association
(incorporated by reference to Exhibit 10.5 to Form 8-K (File No. 1-32740) filed April 2, 2021)
Eleventh Supplemental Indenture, dated April 1, 2021 by and between Energy Transfer LP, Regency Energy Finance Corp., and Wells
Fargo Bank, National Association (incorporated by reference to Exhibit 10.6 to Form 8-K (File No. 1-32740) filed April 2, 2021)
Sixth Supplemental Indenture, dated as of April 30, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp., the
subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, as guarantor, and Wells Fargo Bank, National Association,
as trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-11727) filed April 30, 2015)
Seventh Supplemental Indenture, dated as of May 28, 2015, by and among Regency Energy Partners LP, Regency Energy Finance Corp.,
the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, Energy Transfer Partners, L.P., as co-obligor, and Wells
Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-11727) filed June 1, 2015)
Eighth Supplemental Indenture, dated as of August 10, 2015, by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp.
and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-11727) filed
August 13, 2015)
Ninth Supplemental Indenture, dated as of December 1, 2017 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp.
and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.9 to Form 8-K (File No. 1-31219) filed
December 6, 2017)
Supplemental Indenture No. 6, dated November 3, 2022, between Panhandle Eastern Pipe Line Company, LP, Energy Transfer LP and the
Bank of New York Mellon Trust Company, as Trustee (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-2921) filed
November 17, 2022)
Fifth Supplemental Indenture, dated November 3, 2022, between Panhandle Eastern Pipe Line Company, LP, Energy Transfer LP and the
Bank of New York Mellon Trust Company, as Trustee (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-2921) filed
November 17, 2022)
Eighth Supplemental Indenture, dated November 3, 2022, between Panhandle Eastern Pipe Line Company, LP, Energy Transfer LP and the
Bank of New York Mellon Trust Company, as Trustee (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-2921) filed
November 17, 2022)
Indenture, dated as of December 14, 2022, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company, National Association, as
trustee (incorporated by reference to Exhibit 4.1 to Form 8-K (File No. 1-32740) filed December 14, 2022)
First Supplemental Indenture, dated as of December 14, 2022, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company,
National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed December 14, 2022)
Second Supplemental Indenture, dated as of October 13, 2023, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company,
National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed October 13, 2023
Third Supplemental Indenture, dated as of January 25, 2024, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company,
National Association, as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K (File No. 1-32740) filed January 25, 2024
Fourth Supplemental Indenture, dated as of January 25, 2024, between Energy Transfer LP, as issuer, and U.S. Bank Trust Company,
National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K (File No. 1-32740) filed January 25, 2024
166
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Index to Financial Statements
Exhibit
Number Description
4.66
4.67
4.68
4.69*
4.70*
10.1+
10.2+
10.3+
10.4+
10.5+
10.6+
10.7+
10.8+
10.9+
10.10+
10.11+
10.12+
10.13+
10.14+
10.15*+
10.16
10.17
10.18
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of Series C
Preferred Units (incorporated by reference to Exhibit 4.43 to Form 10-K (File No. 1-32740) filed February 18, 2022)
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of Series D
Preferred Units (incorporated by reference to Exhibit 4.44 to Form 10-K (File No. 1-32740) filed February 18, 2022)
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of Series E
Preferred Units (incorporated by reference to Exhibit 4.45 to Form 10-K (File No. 1-32740) filed February 18, 2022)
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of Series I
Preferred Units
Description of Registrant’s securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 - Description of common
units
Amended and Restated Energy Transfer LP Long-Term Incentive Plan (formerly Amended and Restated Energy Transfer Equity, L.P.
Long-Term Incentive Plan) (incorporated by reference to Exhibit 10.1 to Form 10-K (File No. 1-32740) filed February 23, 2018)
First Amendment to the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2
to Form 10-K (File No. 1-32740) filed February 19, 2021)
Second Amendment to the Amended and Restated Energy Transfer LP Long-Term Incentive Plan (incorporated by reference to Exhibit
10.1 to Form 8-K (File No. 1-32740) filed January 6, 2021)
Energy Transfer LP Long-Term Cash Restricted Unit Plan (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-32740) filed
January 6, 2021)
Form of Cash Unit Award Agreement under the Energy Transfer LP Long-Term Cash Restricted Unit Plan (incorporated by reference to
Exhibit 10.3 to Form 8-K (File No. 1-32740) filed January 6, 2021)
Second Amended and Restated Energy Transfer LP 2008 Long-Term Incentive Plan (formerly Second Amended and Restated Energy
Transfer Partners, L.P. 2008 Long-Term Incentive Plan) (incorporated by reference to Exhibit 4.1 to Form S-8 (File No. 333-229456) filed
January 31, 2019)
Energy Transfer LP 2011 Long-Term Incentive Plan (formerly Regency Energy Partners LP 2011 Long-Term Incentive Plan) (incorporated
by reference to Exhibit 4.2 to Form S-8 (File No 333-229456) filed January 31, 2019)
Energy Transfer LP 2015 Long-Term Incentive Plan, as amended and restated (formerly Sunoco Partners LLC Long-Term Incentive Plan,
as amended and restated) (incorporated by reference to Exhibit 4.3 to Form S-8 (File No. 333-229456) filed January 31, 2019)
Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.26 to Form S-1 (File No. 333-128097)
filed December 20, 2005)
LE GP, LLC Amended and Restated Outside Director Compensation Policy (incorporated by reference to Exhibit 10.9 to Form 10-K (File
No. 1-32740) filed February 22, 2019)
Energy Transfer Deferred Compensation Plan (formerly called Energy Transfer Partners Deferred Compensation Plan) (incorporated by
reference to Exhibit 10.1 to Form 10-Q (File No. 1-11727) filed May 7, 2010)
Amendment No. 1 to the Energy Transfer Deferred Compensation Plan (formerly called Energy Transfer Partners Deferred Compensation
Plan) (incorporated by reference to Exhibit 10.12 to Form 10-K (File No. 1-32740) filed February 18, 2022)
Amendment No. 2 to the Energy Transfer Deferred Compensation Plan (incorporated by reference to Exhibit 10.13 to Form 10-K (File No.
1-32740) filed February 18, 2022)
Energy Transfer LP Annual Bonus Plan (incorporated by reference to Exhibit 10.23 to Form 10-K (File No. 1-32740) filed February 22,
2019)
Energy Transfer LP Amended and Restated Annual Bonus Plan
Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein
(incorporated by reference to Exhibit 99.1 to Form 8-K (File No. 1-32740) filed November 30, 2006)
Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein
(incorporated by reference to Exhibit 99.1 to Form 8-K (File No. 1-32740) filed March 5, 2007)
Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural
Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 to Form 8-K (File No. 1-32740) filed
May 7, 2007)
167
Table of Contents
Index to Financial Statements
Exhibit
Number Description
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
21.1*
22.1
23.1*
31.1*
31.2*
31.3*
32.1**
32.2**
32.3**
97.1*
101*
104
*
**
+
Equity Restructuring Agreement, dated as of January 15, 2018, by and among Energy Transfer Equity, L.P., USA Compression Partners,
LP and USA Compression GP, LLC. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-32740) filed January 16, 2018)
Registration Rights Agreement, dated as of April 2, 2018, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P., USA
Compression Partners, LP and USA Compression Holdings, LLC. (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-
32740) filed April 3, 2018)
Note Purchase Agreement, dated as of May 24, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties
thereto (incorporated by reference to Exhibit 10.56 to Form 10-Q (File No. 1-11727) filed July 10, 2007)
Note Purchase Agreement, dated December 9, 2009, by and among Transwestern Pipeline Company, LLC and the Purchasers parties
thereto (incorporated by reference to Exhibit 10.1 to Form 8-K (File No. 1-11727) filed December 14, 2009)
Amended and Restated Credit Agreement, dated as of April 11, 2022, by and among Energy Transfer LP, as borrower, Wells Fargo Bank,
National Association., as administrative agent, swingline lender and an LC issuer and the lenders party thereto (incorporated by reference
to Exhibit 10.1 of Form 8-K (File No. 1-32740) filed April 12, 2022)
Guarantee of Collection, dated as of April 30, 2013, by and between Regency Energy Partners LP, PEPL Holdings, LLC and Regency
Energy Finance Corp. (incorporated by reference to Exhibit 10.3 to Form 8-K (File No. 1-11727) filed April 30. 2013)
Cushion Gas Litigation Agreement, dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and
HPL Storage LP, as Sellers, and La Grange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line
Company, LP and HPL Resources Company LP, as Companies (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-11727)
filed February 1, 2005)
Guarantee of Collection, made as of March 26, 2012, by Citrus ETP Finance LLC, to Energy Transfer Partners, L.P. (incorporated by
reference to Exhibit 10.1 to Form 8-K (File No. 1-11727) filed March 28, 2012)
Support Agreement, dated March 26, 2012, by and among PEPL Holdings, LLC, Energy Transfer Partners, L.P., and Citrus ETP Finance
LLC (incorporated by reference to Exhibit 10.2 to Form 8-K (File No. 1-11727) filed March 28, 2012)
Form of Commercial Paper Dealer Agreement between Energy Transfer Partners, L.P., as Issuer, and the Dealer party thereto (incorporated
by reference to Exhibit 99.1 to Form 8-K (File No. 1-11727) filed August 22, 2016)
List of Subsidiaries
Issuers and Guarantors of Registered Securities (incorporated by reference to Exhibit 22.1 of Form 10-Q (File No. 1-32740) filed August 5,
2021)
Consent of Grant Thornton LLP
Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Co-Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
Certification of Co-Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002
Certification Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
Energy Transfer LP Executive Officer Incentive Compensation Clawback Policy
Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline eXtensible Business Reporting Language) in this
Form 10-K include: (i) our Consolidated Balance Sheets; (ii) our Consolidated Statements of Operations; (iii) our Consolidated Statements
of Comprehensive Income; (iv) our Consolidated Statement of Equity; (v) our Consolidated Statements of Cash Flows; and (vi) the notes to
our Consolidated Financial Statements
Cover Page Interactive Data File (embedded within the Inline XBRL document)
Filed herewith.
Furnished herewith.
Denotes a management contract or compensatory plan or arrangement.
168
Table of Contents
Index to Financial Statements
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
SIGNATURES
ENERGY TRANSFER LP
By:
LE GP, LLC, its general partner
Date:
February 16, 2024
By:
/s/ A. Troy Sturrock
A. Troy Sturrock
Group Senior Vice President, Controller and Principal Accounting Officer (duly
authorized to sign on behalf of the registrant)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant
and in the capacities and on the dates indicated:
Signature
Title
/s/ Kelcy L. Warren
Kelcy L. Warren
/s/ Marshall S. McCrea, III
Marshall S. McCrea, III
/s/ Thomas E. Long
Thomas E. Long
/s/ Dylan A. Bramhall
Dylan A. Bramhall
/s/ A. Troy Sturrock
A. Troy Sturrock
/s/ Steven R. Anderson
Steven R. Anderson
/s/ Richard D. Brannon
Richard D. Brannon
/s/ Michael K. Grimm
Michael K. Grimm
/s/ John W. McReynolds
John W. McReynolds
/s/ James R. Perry
James R. Perry
/s/ Matthew S. Ramsey
Matthew S. Ramsey
Executive Chairman
Co-Chief Executive Officer and Director
(Co-Principal Executive Officer)
Co-Chief Executive Officer and Director
(Co-Principal Executive Officer)
Executive Vice President and Group Chief Financial Officer
(Principal Financial Officer)
Group Senior Vice President and Controller
(Principal Accounting Officer)
Director
Director
Director
Director
Director
Director
169
Date
February 16, 2024
February 16, 2024
February 16, 2024
February 16, 2024
February 16, 2024
February 16, 2024
February 16, 2024
February 16, 2024
February 16, 2024
February 16, 2024
February 16, 2024
Table of Contents
Index to Financial Statements
ENERGY TRANSFER LP AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
1. Operations and Basis of Presentation
2. Estimates, Significant Accounting Policies and Balance Sheet Detail
3. Acquisitions, Divestitures and Related Transactions
4. Investments in Unconsolidated Affiliates
5. Net Income Per Common Unit
6. Debt Obligations
7. Redeemable Noncontrolling Interests
8. Equity
9. Equity Incentive Plans
10. Income Taxes
11. Regulatory Matters, Commitments, Contingencies and Environmental Liabilities
12. Revenue
13. Lease Accounting
14. Derivative Assets and Liabilities
15. Retirement Benefits
16. Reportable Segments
F - 1
F - 2
F - 4
F - 6
F - 7
F - 8
F - 9
F - 10
F - 10
F - 11
F - 22
F - 25
F - 26
F - 28
F - 33
F - 34
F - 40
F - 42
F - 44
F - 55
F - 62
F - 65
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Table of Contents
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of LE GP, LLC and
Unitholders of Energy Transfer LP
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer LP (a Delaware limited partnership) and subsidiaries (the
“Partnership”) as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income, equity, and cash flows for
each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the “financial statements”). In our opinion,
the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2023 and 2022, and the results of
its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally
accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s
internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 16, 2024 expressed an unqualified
opinion.
Basis for opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial
statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the
Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing
procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to
those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits
also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the
financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or
required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2)
involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion
on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical
audit matters or on the accounts or disclosures to which they relate.
Goodwill Impairment Assessment
As described further in Note 2 to the consolidated financial statements, the Partnership’s consolidated goodwill balance was $4.02 billion as of December
31, 2023. Management evaluates goodwill for impairment annually on October 1st of each year or whenever events or changes in circumstances indicate
potential asset impairment has occurred. As of December 31, 2023, there was $368 million of goodwill associated with a reporting unit within the NGL and
Refined Products Transportation and Services segment in which we identified the Partnership’s determination of the fair value of the reporting unit as a
critical audit matter.
The principal considerations for our determination that the estimation of the fair value of the reporting unit is a critical audit matter are that there are
significant judgments required by management when determining the fair value of the reporting unit. In particular, the fair value estimate was sensitive to
significant assumptions used to estimate future revenues and cash flows, including revenue growth rates, operating expenses, discount rate, and the inherent
uncertainty around future market conditions as well as valuation methodologies applied by the Partnership.
Our audit procedures related to the valuation of the reporting unit within the NGL and Refined Products Transportation and Services segment included the
following, among others:
• We tested the effectiveness of controls relating to management’s review of the assumptions used to develop the future cash flows, the discount rate
used, and valuation methodologies applied.
F - 2
Table of Contents
Index to Financial Statements
• We assessed the reasonableness of management’s forecast of future projected results by comparing such items to industry projections and
conditions found in industry reports.
• We tested forecasted revenues and expected future cash flows by comparing forecasted amounts to actual historical results to identify material
changes, corroborating the basis for increases in forecasted revenues and expected future cash flows.
• We tested significant operating expenses and cash expenditures by comparing to historical trends and evaluating significant deviations from recent
actual amounts.
We utilized our valuation specialists to evaluate:
•
•
The methodologies used and whether they were acceptable for the underlying assets or operations and whether such methodologies were being
applied correctly, and
The appropriateness of the discount rate by developing an independent range of acceptable discount rates and comparing those ranges to the
amounts selected and applied by management.
Fair Value of Assets Acquired in the Acquisition of Crestwood Equity Partners LP
As described in Note 3 to the consolidated financial statements, on November 3, 2023, the Partnership completed the acquisition of Crestwood Equity
Partners LP (“Crestwood") and the assets acquired and liabilities assumed were required to be recorded at fair value as of the acquisition date. The
Partnership used an independent valuation specialist to assist in the preparation of the valuation. The acquired fair value of personal property and customer-
relationship intangible assets were valued at $4.46 billion and $1.11 billion, respectively. The excess purchase price over the fair value of the net assets
acquired was recorded to goodwill. We identified the fair value determination of the personal property and customer-relationship intangible assets to be a
critical audit matter.
The principal considerations for our determination that the estimation of the fair value of the personal property and customer-relationship intangible assets
as a critical audit matter are that there are significant judgments required by management when determining the fair value. In particular, the significant
judgments were the replacement cost assumptions and methodology used for personal property as well as the estimated long-term cash flows and the
discount rate related to the fair value of the customer-relationship intangible assets. This led to a high degree of auditor judgment, subjectivity, and effort in
performing procedures along with the involvement of our valuation specialists to assist in performing these procedures and evaluating the audit evidence
obtained.
Our audit procedures related to the valuation of personal property and customer-relationship intangible assets included the following, among others:
• We tested the effectiveness of controls relating to management’s review of the valuation methodologies applied, assumptions used to develop the
long-term cash flows, and the reconciliation of cash flows prepared by management to the data used in the valuation.
• We assessed the objectivity, experience, and qualifications of management’s independent valuation specialist.
• We tested expected future cash flows used in the valuation of customer-relationship intangible assets by comparing forecasted amounts to actual
historical results to identify material changes, corroborating the basis for increases in future cash flows.
• We tested significant capital expenditures projections and obtained evidence of approvals of capital projects.
We utilized our valuation specialists to evaluate:
•
•
•
The methodologies used to estimate the fair value of personal property and whether they were acceptable for the underlying assets or operations
and whether such methodologies were reasonably applied,
The appropriateness of the replacement cost of personal property, by evaluating whether the replacement cost assigned was reasonable for the
underlying assets based upon a reasonable range, and
The methodology and assumptions used to value the customer-relationship intangible assets, including the discount rate by developing an
independent range of acceptable discount rates and comparing those ranges to the amounts selected and applied by management.
/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2004.
Dallas, Texas
February 16, 2024
F - 3
Table of Contents
Index to Financial Statements
Current assets:
Cash and cash equivalents
Accounts receivable, net
Accounts receivable from related companies
Inventories
Income taxes receivable
Derivative assets
Other current assets
Total current assets
Property, plant and equipment
Accumulated depreciation and depletion
Property, plant and equipment, net
Investments in unconsolidated affiliates
Lease right-of-use assets, net
Other non-current assets, net
Intangible assets, net
Goodwill
Total assets
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
December 31,
2023
2022
ASSETS
$
161 $
9,047
101
2,478
67
66
513
12,433
114,932
(29,581)
85,351
3,097
826
1,733
6,239
4,019
113,698 $
$
257
8,466
93
2,461
68
10
726
12,081
105,996
(25,685)
80,311
2,893
819
1,558
5,415
2,566
105,643
The accompanying notes are an integral part of these consolidated financial statements.
F - 4
Table of Contents
Index to Financial Statements
Current liabilities:
Accounts payable
Accounts payable to related companies
Derivative liabilities
Operating lease current liabilities
Accrued and other current liabilities
Current maturities of long-term debt
Total current liabilities
Long-term debt, less current maturities
Non-current derivative liabilities
Non-current operating lease liabilities
Deferred income taxes
Other non-current liabilities
Commitments and contingencies
Redeemable noncontrolling interests
Equity:
Limited Partners:
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(Dollars in millions)
LIABILITIES AND EQUITY
December 31,
2023
2022
$
$
6,663 $
21
8
56
3,521
1,008
11,277
51,380
4
778
3,931
1,611
6,952
17
23
45
3,329
2
10,368
48,260
23
798
3,701
1,341
778
493
6,459
30,197
(2)
28
36,682
7,257
43,939
113,698 $
6,051
26,960
(2)
16
33,025
7,634
40,659
105,643
Preferred Unitholders (113,648,967 and 72,184,780 units authorized, issued and outstanding as of December
31, 2023 and 2022, respectively)
Common Unitholders (3,367,525,806 and 3,094,445,367 units authorized, issued and outstanding as of
December 31, 2023 and 2022, respectively)
General Partner
Accumulated other comprehensive income
Total partners’ capital
Noncontrolling interests
Total equity
Total liabilities and equity
The accompanying notes are an integral part of these consolidated financial statements.
F - 5
Table of Contents
Index to Financial Statements
REVENUES:
Refined product sales
Crude sales
NGL sales
Gathering, transportation and other fees
Natural gas sales
Other
Total revenues
COSTS AND EXPENSES:
Cost of products sold
Operating expenses
Depreciation, depletion and amortization
Selling, general and administrative
Impairment losses and other
Total costs and expenses
OPERATING INCOME
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized
Equity in earnings of unconsolidated affiliates
Gains (losses) on extinguishments of debt
Gains on interest rate derivatives
Non-operating litigation-related loss
Other, net
INCOME BEFORE INCOME TAX EXPENSE
Income tax expense
NET INCOME
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per unit data)
2023
Years Ended December 31,
2022
2021
$
$
$
$
23,389 $
23,492
15,957
11,428
3,259
1,061
78,586
60,541
4,368
4,385
985
12
70,291
8,295
(2,578)
383
2
36
(627)
86
5,597
303
5,294
1,299
60
3,935
3
463
3,469 $
1.10 $
1.09 $
26,020 $
23,473
20,114
10,907
8,535
827
89,876
72,232
4,338
4,164
1,018
386
82,138
7,738
(2,306)
257
—
293
—
90
6,072
204
5,868
1,061
51
4,756
4
422
4,330 $
1.40 $
1.40 $
17,766
15,299
15,243
9,229
9,159
721
67,417
50,395
3,574
3,817
818
21
58,625
8,792
(2,267)
246
(38)
61
—
77
6,871
184
6,687
1,167
50
5,470
6
285
5,179
1.89
1.89
Less: Net income attributable to noncontrolling interests
Less: Net income attributable to redeemable noncontrolling interests
NET INCOME ATTRIBUTABLE TO PARTNERS
General Partner’s interest in net income
Preferred Unitholders’ interest in net income
Common Unitholders’ interest in net income
NET INCOME PER COMMON UNIT:
Basic
Diluted
The accompanying notes are an integral part of these consolidated financial statements.
F - 6
Table of Contents
Index to Financial Statements
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
Net income
Other comprehensive income (loss), net of tax:
Change in value of available-for-sale securities
Actuarial gain (loss) relating to pension and other postretirement benefits
Foreign currency translation adjustment
Change in other comprehensive income from unconsolidated affiliates
Comprehensive income
Less: Comprehensive income attributable to noncontrolling interests
Less: Comprehensive income attributable to redeemable noncontrolling interests
Comprehensive income attributable to partners
$
2023
Years Ended December 31,
2022
2021
$
5,294 $
5,868 $
4
13
(6)
1
12
5,306
1,299
60
3,947 $
(10)
(12)
(6)
24
(4)
5,864
1,055
51
4,758 $
6,687
1
12
4
3
20
6,707
1,170
50
5,487
The accompanying notes are an integral part of these consolidated financial statements.
F - 7
Table of Contents
Index to Financial Statements
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
(Dollars in millions)
Common
Unitholders
Preferred
Unitholders
General
Partner
Accumulated
Other
Comprehensive
Income
Non-
controlling
Interests
Total
Balance, December 31, 2020
$
Preferred units converted in Rollup Mergers
Distributions to partners
Distributions to noncontrolling interests
Common units repurchased
Units issued
Capital contributions from noncontrolling interests
Enable acquisition
Other comprehensive income, net of tax
Other, net
Net income, excluding amounts attributable to
redeemable noncontrolling interests
Balance, December 31, 2021
Distributions to partners
Distributions to noncontrolling interests
Capital contributions from noncontrolling interests
Energy Transfer Canada sale
Other comprehensive income (loss), net of tax
Other, net
Net income, excluding amounts attributable to
redeemable noncontrolling interests
Balance, December 31, 2022
Distributions to partners
Distributions to noncontrolling interests
Capital contributions from noncontrolling interests
Other comprehensive income, net of tax
Lotus Midstream acquisition
Crestwood acquisition
Other, net
Net income, excluding amounts attributable to
redeemable noncontrolling interests
Balance, December 31, 2023
18,531 $
—
(1,616)
—
(31)
—
—
3,117
—
50
5,179
25,230
(2,623)
—
—
—
—
23
4,330
26,960
(3,777)
—
—
—
574
2,953
18
— $
4,768
(280)
—
—
889
—
392
—
(3)
285
6,051
(422)
—
—
—
—
—
422
6,051
(468)
—
—
—
—
413
—
(8) $
—
(2)
—
—
—
—
—
—
—
6
(4)
(2)
—
—
—
—
—
4
(2)
(3)
—
—
—
—
—
—
6 $
—
—
—
—
—
—
—
17
—
—
23
—
—
—
(9)
2
—
—
16
—
—
—
12
—
—
—
12,859 $
(4,768)
—
(1,487)
—
—
226
34
3
11
1,167
8,045
—
(1,547)
405
(337)
(6)
13
1,061
7,634
—
(1,691)
3
—
—
—
12
3,469
30,197 $
$
463
6,459 $
3
(2) $
—
28 $
1,299
7,257 $
31,388
—
(1,898)
(1,487)
(31)
889
226
3,543
20
58
6,637
39,345
(3,047)
(1,547)
405
(346)
(4)
36
5,817
40,659
(4,248)
(1,691)
3
12
574
3,366
30
5,234
43,939
The accompanying notes are an integral part of these consolidated financial statements.
F - 8
Table of Contents
Index to Financial Statements
ENERGY TRANSFER LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
2023
Years Ended December 31,
2022
2021
OPERATING ACTIVITIES:
Net income
Reconciliation of net income to net cash provided by operating activities:
Depreciation, depletion and amortization
Deferred income taxes
Inventory valuation adjustments
Non-cash compensation expense
Impairment losses
(Gains) losses on extinguishments of debt
Distributions on unvested awards
Equity in earnings of unconsolidated affiliates
Distributions from unconsolidated affiliates
Other non-cash
Net change in operating assets and liabilities, net of effects of acquisitions
Net cash provided by operating activities
INVESTING ACTIVITIES:
Cash paid for Crestwood acquisition, net of cash received
Cash paid for Lotus Midstream acquisition, net of cash received
Cash paid for other acquisitions, net of cash received
Capital expenditures, excluding allowance for equity funds used during construction
Contributions in aid of construction costs
Contributions to unconsolidated affiliates
Distributions from unconsolidated affiliates in excess of cumulative earnings
Proceeds from sale of Energy Transfer Canada interest
Proceeds from sales of other assets
Other
Net cash used in investing activities
FINANCING ACTIVITIES:
Proceeds from borrowings
Repayments of debt
Preferred units issued for cash
Capital contributions from noncontrolling interests
Distributions to partners
Distributions to noncontrolling interests
Distributions to redeemable noncontrolling interests
Common units repurchased under buyback program
Debt issuance costs
Other
Net cash used in financing activities
Decrease in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
$
5,294 $
5,868 $
4,385
203
114
130
12
(2)
(68)
(383)
353
(32)
(451)
9,555
(288)
(930)
(111)
(3,134)
40
(6)
63
—
38
3
(4,325)
32,130
(31,416)
—
3
(4,248)
(1,691)
(59)
—
(45)
—
(5,326)
(96)
257
161 $
4,164
187
(5)
115
386
—
(73)
(257)
232
(64)
(1,502)
9,051
—
—
(1,141)
(3,381)
56
—
62
302
78
2
(4,022)
28,838
(29,681)
—
405
(3,047)
(1,547)
(49)
—
(27)
—
(5,108)
(79)
336
257 $
$
6,687
3,817
141
(190)
111
21
38
(47)
(246)
212
103
515
11,162
—
—
(205)
(2,822)
43
(4)
167
—
45
1
(2,775)
21,267
(27,318)
889
226
(1,898)
(1,487)
(49)
(31)
(14)
(3)
(8,418)
(31)
367
336
The accompanying notes are an integral part of these consolidated financial statements.
F - 9
Table of Contents
Index to Financial Statements
ENERGY TRANSFER LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Tabular dollar and unit amounts, except per unit data, are in millions)
1. OPERATIONS AND BASIS OF PRESENTATION:
The consolidated financial statements presented herein contain the results of Energy Transfer LP and its subsidiaries (the “Partnership,” “we,” “us,”
“our” or “Energy Transfer”).
On April 1, 2021, Energy Transfer, ETO and certain of ETO’s subsidiaries consummated several internal reorganization transactions (the “Rollup
Mergers”). In connection with the Rollup Mergers, ETO merged with and into Energy Transfer, with Energy Transfer surviving. The impacts of the
Rollup Mergers also included the following:
• All of ETO’s long-term debt was assumed by Energy Transfer.
•
•
Each issued and outstanding ETO preferred unit was converted into the right to receive one newly created Energy Transfer preferred unit. A
description of the Energy Transfer Preferred Units is included in Note 8.
Each of ETO’s issued and outstanding Class K, Class L, Class M and Class N units were converted into an aggregate 675,625,000 newly created
Class B Units representing limited partner interests in Energy Transfer. All of the Class B Units are held by ETP Holdco, a wholly owned
subsidiary of Energy Transfer.
Our consolidated financial statements reflect the following reportable segments:
•
•
intrastate transportation and storage;
interstate transportation and storage;
• midstream;
• NGL and refined products transportation and services;
•
•
•
•
crude oil transportation and services;
investment in Sunoco LP;
investment in USAC; and
all other.
The Partnership owns and operates intrastate natural gas pipeline systems and storage facilities that are engaged in the business of purchasing,
gathering, transporting, processing and marketing natural gas and NGLs in the states of Texas, Oklahoma and Louisiana.
The Partnership also owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various
markets in the United States.
The Partnership is also engaged in midstream services, focusing on providing gathering, processing, compression, treating and transportation of natural
gas in some of the most prolific natural gas producing regions in the United States, including the Permian, Anadarko, Arkoma, Hugoton, Powder River
and Williston basins, as well as the Eagle Ford, Haynesville, Barnett, Marcellus and Utica shales.
The Partnership’s operations also include crude oil, NGL and refined products transportation, terminalling services, acquisition and marketing
activities, as well as NGL storage, fractionation and LNG regasification.
The Partnership owns a controlling interest in Sunoco LP which is engaged in the wholesale distribution of motor fuels to convenience stores,
independent dealers, commercial customers and distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated
convenience stores and retail fuel sites. As of December 31, 2023, our interest in Sunoco LP consisted of 100% of the general partner and IDRs, as
well as 28.5 million common units.
The Partnership owns a controlling interest in USAC which provides compression services to producers, processors, gatherers and transporters of
natural gas and crude oil. As of December 31, 2023, our interest in USAC consisted of 100% of the general partner and 46.1 million common units.
Basis of Presentation. The consolidated financial statements of Energy Transfer LP presented herein have been prepared in accordance with GAAP
and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned
F - 10
Table of Contents
Index to Financial Statements
subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions
and accounts are eliminated in consolidation.
The consolidated financial statements of Energy Transfer presented herein include the results of operations of our controlled subsidiaries, including
Sunoco LP and USAC.
2. ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting period.
The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently,
the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume
estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements.
Management believes that the estimated operating results represent the actual results in all material respects.
Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are
hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent
realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities
resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.
Regulatory Accounting – Regulatory Assets and Liabilities
Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that
segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities, in accordance
with Accounting Standards Codification (“ASC”) Topic 980. The application of these accounting policies allows certain of our regulated entities to
defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be
allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of
operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same
amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of
regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet
the criteria for application of regulatory accounting treatment under ASC Topic 980 for these entities, the regulatory assets and liabilities related to
those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of
regulatory accounting treatment occurs.
Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of the FERC in accordance with the NGA
and NGPA, Panhandle does not currently apply ASC Topic 980 in its GAAP-basis consolidated financial statements, primarily due to the level of
discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information
Cash and cash equivalents include all cash on hand, demand deposits and investments with original maturities of three months or less. We consider
cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an
insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may
be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
F - 11
Table of Contents
Index to Financial Statements
The net change in operating assets and liabilities, net of effects of acquisitions, included in cash flows from operating activities is comprised as
follows:
Accounts receivable
Accounts receivable from related companies
Inventories
Other current assets
Other non-current assets, net
Accounts payable
Accounts payable to related companies
Accrued and other current liabilities
Other non-current liabilities
Derivative assets and liabilities, net
Net change in operating assets and liabilities, net of effects of acquisitions
2023
Years Ended December 31,
2022
2021
$
$
(171) $
(5)
35
221
(125)
(501)
(38)
209
(33)
(43)
(451) $
(863) $
23
(361)
(326)
146
25
6
131
66
(349)
(1,502) $
Non-cash investing and financing activities and supplemental cash flow information are as follows:
NON-CASH INVESTING AND FINANCING ACTIVITIES:
(1)
Accrued capital expenditures
Units issued in connection with the Enable acquisition
Units issued in connection with the Crestwood acquisition
Units issued in connection with the Lotus Midstream acquisition
Lease assets obtained in exchange for new lease liabilities
Acquisition of interest in unconsolidated affiliate
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest, net of interest capitalized
Cash paid for income taxes (net of refunds)
(1)
(1)
2023
Years Ended December 31,
2022
2021
$
$
442 $
—
3,366
574
23
—
2,298 $
103
575 $
—
—
—
42
—
2,167 $
54
(3,356)
38
(19)
(216)
1
3,834
(34)
238
117
(88)
515
464
3,509
—
—
18
49
2,188
41
(1)
See Note 3 for additional information.
Accounts Receivable, net
Our operations deal with a variety of counterparties across the energy sector. Internal credit ratings and credit limits are assigned to all counterparties
and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment
grade depending on the internal credit rating and level of commercial activity with the counterparty.
We have a diverse portfolio of customers; however, because of the midstream and transportation services we provide, many of our customers are
engaged in the exploration and production sector. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables.
Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do
not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of
security. We establish an allowance for credit losses on trade receivables based on the expected ultimate recovery of these receivables and consider
many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual
customers, sectors, and transactions that might impact collectability. Changes in the allowance are recorded as a component of operating expenses;
reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when
our efforts have been unsuccessful in collecting the amount due.
F - 12
Table of Contents
Index to Financial Statements
Inventories
Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil and spare parts, all of which are valued at the lower
of cost or net realizable value utilizing the weighted-average cost method.
Sunoco LP’s fuel inventories are stated at the lower of cost or market using the last-in-first-out (“LIFO”) method. As of December 31, 2023 and 2022,
Sunoco LP’s fuel inventory balance included lower of cost or market reserves of $230 million and $116 million, respectively. For the years ended
December 31, 2023, 2022 and 2021, the Partnership’s consolidated statements of operations and comprehensive income did not include any material
amounts of income from the liquidation of Sunoco LP’s LIFO fuel inventory. For the years ended December 31, 2023, 2022 and 2021, the
Partnership’s cost of products sold included an unfavorable inventory adjustment of $114 million, a favorable inventory adjustment of $5 million and a
favorable inventory adjustment of $190 million, respectively, related to Sunoco LP’s LIFO inventory.
The Partnership’s inventories consisted of the following:
Natural gas, NGLs and refined products
Crude oil
Spare parts and other
Total inventories
December 31,
2023
2022
$
$
1,658 $
258
562
2,478 $
1,802
246
413
2,461
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged
inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Other Current Assets
Other current assets consisted of the following:
Deposits paid to vendors
Prepaid expenses and other
Total other current assets
Property, Plant and Equipment, net
December 31,
2023
2022
$
$
205 $
308
513 $
334
392
726
Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the
estimated useful or FERC-mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the
useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental
contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the
construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural
gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and
equipment is retired or sold, any gain or loss is included in our consolidated statements of operations.
Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such
assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying
amount of such assets to fair value.
For the years ended December 31 2023, 2022 and 2021, USAC recognized fixed asset impairments of $12 million, $1 million and $5 million,
respectively, related to its compression equipment as a result of its evaluation of the future deployment of idle fleet.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during
construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facilities when the related costs
are incurred. AFUDC is calculated under guidelines prescribed
F - 13
Table of Contents
Index to Financial Statements
by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in
construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Components and useful lives of property, plant and equipment were as follows:
Land and improvements
Buildings and improvements (1 to 45 years)
Pipelines and equipment (5 to 83 years)
Product storage and related facilities (2 to 83 years)
Right of way (20 to 83 years)
Other (1 to 48 years)
Construction work-in-process
Less – Accumulated depreciation and depletion
Property, plant and equipment, net
We recognized the following amounts for the periods presented:
Depreciation, depletion and amortization expense
Capitalized interest
Investments in Unconsolidated Affiliates
December 31,
2023
2022
1,529 $
3,848
88,195
7,978
7,379
3,688
2,315
114,932
(29,581)
85,351 $
1,427
3,546
82,353
7,274
6,252
2,739
2,405
105,996
(25,685)
80,311
$
$
2023
Years Ended December 31,
2022
2021
$
3,986 $
77
3,774 $
112
3,465
135
We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for
an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an
investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary.
Other Non-Current Assets, net
Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following:
Crude pipeline linefill and tank bottoms
Regulatory assets
Pension assets
Deferred charges
Restricted funds
Other
Total other non-current assets, net
December 31,
2023
2022
$
$
598 $
48
145
148
121
673
1,733 $
489
55
129
140
121
624
1,558
Restricted funds include an immaterial amount of restricted cash primarily held in our wholly owned captive insurance companies.
Intangible Assets, net
Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and
the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized.
F - 14
Table of Contents
Index to Financial Statements
Components and useful lives of intangible assets were as follows:
December 31, 2023
December 31, 2022
Gross Carrying
Amount
Accumulated
Amortization
Gross Carrying
Amount
Accumulated
Amortization
Amortizable intangible assets:
Customer relationships, contracts and agreements (3 to 46
years)
Patents (10 years)
Trade names (20 years)
Other (5 to 20 years)
Total amortizable intangible assets
Non-amortizable intangible assets:
Trademarks
Other
Total non-amortizable intangible assets
Total intangible assets
$
$
9,098 $
48
66
12
9,224
302
12
314
9,538 $
(3,196) $
(48)
(44)
(11)
(3,299)
—
—
—
(3,299) $
7,884 $
48
66
12
8,010
302
12
314
8,324 $
(2,807)
(48)
(41)
(13)
(2,909)
—
—
—
(2,909)
Aggregate amortization expense of intangible assets was as follows:
Reported in depreciation, depletion and amortization expense
$
399 $
390 $
352
2023
Years Ended December 31,
2022
2021
Estimated aggregate amortization of intangible assets for the next five years is as follows:
Years Ending December 31:
2024
2025
2026
2027
2028
$
434
423
417
400
397
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets
may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the
carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances
dictate.
Goodwill
Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test
was performed during the fourth quarter.
Changes in the carrying amount of goodwill were as follows:
Intrastate
Transportation
and Storage
Interstate
Transportation
and Storage
Midstream
NGL and Refined
Products
Transportation
and Services
Crude Oil
Transportation
and Services
Investment in
Sunoco LP
Investment in
USAC
All Other
Total
Balance, December 31, 2021
Acquired
Balance, December 31, 2022
Acquired
Other
Balance, December 31, 2023
$
$
—
—
—
—
—
—
$
$
—
—
—
—
—
—
$
$
—
—
—
601
—
601
$
$
693
—
693
191
—
884
$
$
190
—
190
663
—
853
$
$
1,568
33
1,601
—
(2)
$
1,599
$
—
—
—
—
—
—
$
$
82
—
82
—
—
82
$
$
2,533
33
2,566
1,455
(2)
4,019
F - 15
Table of Contents
Index to Financial Statements
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price
allocation is finalized. During the fourth quarter of 2023, $1.46 billion of goodwill was recorded in conjunction with the acquisition of Crestwood,
which is not expected to be deductible for tax purposes. In 2022, Sunoco LP recorded $33 million of goodwill in conjunction with its acquisitions.
The Partnership determines the fair value of our reporting units using the discounted cash flow method, the guideline company method, or a weighted
combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment
and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted
average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment
assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different
calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership
determines fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present
value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from
one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management.
Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under
the guideline company method, the Partnership determines the estimated fair value of each of our reporting units by applying valuation multiples of
comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations
using a three year average. In addition, the Partnership estimates a reasonable control premium representing the incremental value that accrues to the
majority owner from the opportunity to dictate the strategic and operational actions of the business. The fair value estimates used in the long-lived
asset and goodwill tests were primarily based on Level 3 inputs of the fair value hierarchy.
Management does not believe that any of the goodwill balances in its reporting units is currently at significant risk of impairment; however, of the
$4.02 billion of goodwill on the Partnership’s consolidated balance sheet as of December 31, 2023, approximately $368 million is recorded in
reporting units for which the estimated fair value exceeded the carrying value by approximately 20% or less in the most recent quantitative test.
Asset Retirement Obligations
We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement
of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases
on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level
3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion)
or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an
ARO in the periods in which management can reasonably estimate the settlement dates.
As of December 31, 2023 and 2022, other non-current liabilities in the Partnership’s consolidated balance sheets included AROs of $410 million and
$362 million, respectively. For the years ended December 31, 2023, 2022 and 2021 aggregate accretion expense related to AROs was $10 million,
$4 million and $12 million, respectively.
Except for the AROs discussed above, management was not able to reasonably measure the fair value of AROs as of December 31, 2023 and 2022, in
most cases because the settlement dates were indeterminable. Although a number of onshore assets in our systems are subject to agreements or
regulations that give rise to an ARO upon discontinued use of these assets, AROs were not recorded because these assets have an indeterminate
removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Our subsidiaries also have legal
obligations for several other assets at previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations
will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these
underlying assets, our subsidiaries are legally or contractually required to abandon in place or remove the asset. We believe we may have additional
AROs related to pipeline assets and storage tanks, for which it is not possible to estimate whether or when the AROs will be settled. Consequently,
these AROs cannot be measured at this time. Sunoco LP also has AROs related to the estimated future cost to remove underground storage tanks.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will
continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power
generation activities, management expects supply and demand to exist for the
F - 16
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Index to Financial Statements
foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing
systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and
processing systems themselves will remain intact indefinitely.
As of December 31, 2023 and 2022, other non-current assets on the Partnership’s consolidated balance sheets included $31 million and $27 million,
respectively, of funds that were legally restricted for the purpose of settling AROs.
Accrued and Other Current Liabilities
Accrued and other current liabilities consisted of the following:
Interest payable
Customer advances and deposits
Accrued capital expenditures
Accrued wages and benefits
Taxes payable other than income taxes
Exchanges payable
Deferred revenue
Other
Total accrued and other current liabilities
December 31,
2023
2022
$
$
637 $
240
442
406
646
163
312
675
3,521 $
559
222
575
376
519
224
268
586
3,329
In certain circumstances, customer advances and deposits are received from our customers as prepayments for natural gas deliveries in the following
month. Prepayments and security deposits may be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interests
Our redeemable noncontrolling interests relate to certain preferred unitholders of our consolidated subsidiaries that have the option to convert their
preferred units to such subsidiary’s common units at the election of the holders and the noncontrolling interest holders in our consolidated subsidiaries
that have the option to sell their interests to us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total
equity and reflected as redeemable noncontrolling interests on our consolidated balance sheets. See Note 7 for further information.
Environmental Remediation
We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and
reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and
related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists
for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in
the range is accrued.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value.
We have commodity derivatives and interest rate derivatives that are accounted for as assets and liabilities at fair value in our consolidated balance
sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level
1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity
derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs
observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation
since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our
clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation
of our interest rate derivatives as Level 2 as the primary input, the LIBOR or SOFR curve, is based on quotes from an active exchange of futures for
the same period as the
F - 17
Table of Contents
Index to Financial Statements
future interest swap settlements. Level 3 inputs are unobservable. During the year ended December 31, 2023, no transfers were made between any
levels within the fair value hierarchy.
The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of
December 31, 2023 and 2022 based on inputs used to derive their fair values:
Assets:
Interest rate derivatives
Commodity derivatives:
Natural Gas:
Basis Swaps FERC/NYMEX
Swing Swaps IFERC
Fixed Swaps/Futures
Forward Physical Contracts
Power:
Forwards
Futures
NGLs – Forwards/Swaps
Refined Products – Futures
Crude – Forwards/Swaps
Total commodity derivatives
Other non-current assets
Total assets
Liabilities:
Interest rate derivatives
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX
Swing Swaps IFERC
Fixed Swaps/Futures
Options – Puts
Power:
Forwards
Futures
NGL/Refined Products Option - Puts
NGL/Refined Products Option - Calls
NGLs – Forwards/Swaps
Refined Products – Futures
Crude – Forwards/Swaps
Total commodity derivatives
Total liabilities
Fair Value Measurements at
December 31, 2023
Fair Value Total
Level 1
Level 2
$
6 $
— $
24
20
77
8
57
8
336
35
45
610
31
647 $
(4) $
(3)
(2)
(16)
(2)
(56)
(8)
(1)
(1)
(316)
(18)
(37)
(460)
(464) $
24
20
77
—
57
8
336
35
45
602
20
622 $
— $
(3)
(2)
(16)
(2)
(56)
(8)
(1)
(1)
(316)
(18)
(37)
(460)
(460) $
$
$
$
F - 18
6
—
—
—
8
—
—
—
—
—
8
11
25
(4)
—
—
—
—
—
—
—
—
—
—
—
—
(4)
Table of Contents
Index to Financial Statements
Assets:
Interest rate derivatives
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX
Swing Swaps IFERC
Fixed Swaps/Futures
Forward Physical Contracts
Power:
Forwards
Futures
NGLs – Forwards/Swaps
Refined Products – Futures
Crude - Forwards/Swaps
Total commodity derivatives
Other non-current assets
Total assets
Liabilities:
Interest rate derivatives
Commodity derivatives:
Natural Gas:
Basis Swaps IFERC/NYMEX
Swing Swaps IFERC
Fixed Swaps/Futures
Forward Physical Contracts
Power:
Forwards
Futures
NGLs – Forwards/Swaps
Refined Products – Futures
Crude - Forwards/Swaps
Total commodity derivatives
Total liabilities
Fair Value Measurements at
December 31, 2022
Fair Value Total
Level 1
Level 2
$
— $
— $
60
75
113
10
52
3
317
20
38
688
27
715 $
(23) $
(25)
(12)
(4)
(2)
(51)
(3)
(358)
(59)
(12)
(526)
(549) $
$
$
$
—
—
—
—
10
52
—
—
—
—
62
9
71
60
75
113
—
—
3
317
20
38
626
18
644 $
— $
(23)
(25)
(12)
(4)
—
(3)
(358)
(59)
(12)
(473)
(473) $
—
—
(2)
(51)
—
—
—
—
(53)
(76)
Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate
fair value and carrying amount of our debt obligations as of December 31, 2023 was $51.93 billion and $52.39 billion, respectively. As of
December 31, 2022, the aggregate fair value and carrying amount of our debt obligations was $45.42 billion and $48.26 billion, respectively. The fair
value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities.
Contributions in Aid of Construction Costs
On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such
arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted
against our project costs as they are received.
F - 19
Table of Contents
Index to Financial Statements
Shipping and Handling Costs
Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and
treating which are included in operating expenses.
Costs and Expenses
Cost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of
appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations
personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses
include all partnership related expenses and compensation for executive, partnership and administrative personnel.
We record the collection of taxes to be remitted to government authorities on a net basis, except for consumer excise taxes collected by Sunoco LP on
sales of refined products and merchandise which are included in both revenues and costs and expenses in the consolidated statements of operations,
with no effect on net income. For the years ended December 31, 2023, 2022 and 2021, excise taxes collected by Sunoco LP were $274 million,
$285 million and $332 million, respectively.
Issuances of Subsidiary Units
We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or
comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the
amount of consideration received or paid and the amount by which the noncontrolling interests are adjusted as a change in partners’ capital.
Related Party Transactions
The Partnership regularly enters into related party transactions with several of its unconsolidated affiliates. In addition to commercial transactions,
these transactions include the provision of certain management services and leases of certain assets. While the Partnership believes that such related
party transactions generally reflect market rates, the pricing under such agreements may not be comparable to similar transactions with unaffiliated
third parties. For the years ended December 31, 2023, 2022 and 2021, the Partnership’s consolidated income statements reflect revenues from related
parties of $626 million, $391 million and $410 million, respectively.
Income Taxes
Energy Transfer is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or
losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners.
Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between
the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our
Partnership Agreement. We do not have access to information regarding each partner’s individual tax basis in our limited partner interests.
As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue
Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our
qualifying income does not meet this statutory requirement, Energy Transfer would be taxed as a corporation for federal and state income tax purposes.
For the years ended December 31, 2023, 2022 and 2021, our qualifying income met the statutory requirement.
The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local, and foreign income taxes. These
corporate subsidiaries include ETP Holdco, Sunoco Retail LLC, and Aloha, among others. The Partnership and its corporate subsidiaries account for
income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the
financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured
using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are
established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized.
F - 20
Table of Contents
Index to Financial Statements
The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex
tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining
uncertain tax positions. The benefits of uncertain tax positions are recorded in our consolidated financial statements only after determining a more-
likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances
change, we reassess these probabilities and record any changes through the provision for income taxes.
Accounting for Derivative Instruments and Hedging Activities
For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the
gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and
related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate
valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives,
and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the
inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting
changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by
including changes in the fair value of the derivative in net income for the period.
If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of
products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any
ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated
statements of operations.
Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash
flows from the items being hedged.
If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in
AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in
earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is
probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of
time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products
sold in the consolidated statements of operations.
We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are
accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we
report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges
for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the
consolidated statements of operations.
Equity Incentive Compensation
For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined
based on the market price of the underlying common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the
award at the end of each reporting period based on the market price of the underlying common units as of the reporting date, and the fair value is
recorded in other non-current liabilities on our consolidated balance sheets.
Pensions and Other Postretirement Benefit Plans
The Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference
between the fair value of the plan assets and the benefit obligation (the projected benefit obligation for pension plans and the accumulated
postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is
recognized as a liability. Changes in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for
entities applying regulatory accounting, as a regulatory asset or regulatory liability.
F - 21
Table of Contents
Index to Financial Statements
Allocation of Income
For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated
among the partners in accordance with their percentage interests.
3. ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS:
Crestwood Acquisition
On November 3, 2023, Energy Transfer acquired Crestwood, which owns gathering and processing assets located in the Williston, Delaware and
Powder River basins. Under the terms of the merger agreement, holders of Crestwood common units received 2.07 Energy Transfer common units for
each Crestwood common unit held by them (the “Common Unit Merger Consideration”). Additionally, each outstanding Crestwood preferred unit was,
at the election of the holder of such Crestwood preferred unit, either, (i) converted into a Series I Preferred Unit, which is a new preferred unit of
Energy Transfer that has substantially similar terms, including with respect to economics and structural protections, as the Crestwood preferred units;
(ii) redeemed in exchange for $9.857484 in cash plus accrued and unpaid distributions to the date of such redemption; or (iii) converted into a
Crestwood common unit at the then-applicable conversion ratio of one Crestwood common unit for ten Crestwood preferred units, and such Crestwood
common units then received the Common Unit Merger Consideration.
In total, consideration issued in the transaction included approximately 216 million Energy Transfer common units, 41 million Series I Preferred Units
and $300 million in cash. Concurrent with the closing of the Crestwood acquisition, the Partnership assumed $2.85 billion aggregate principal amount
of Crestwood senior notes and terminated its revolving credit facility, which included the repayment of $613 million in outstanding borrowings.
The Crestwood acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and
liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the
fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the
utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were
valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.
The following table summarizes the assumed allocation of the purchase price among the assets acquired and liabilities assumed:
At November 3, 2023
Total current assets
Property, plant and equipment, net
Investments in unconsolidated affiliates
Lease right-of-use assets, net
Other non-current assets
Intangible assets, net
Goodwill
Total assets
Total current liabilities
Long-term debt, less current maturities
Other non-current liabilities
Total liabilities
Noncontrolling interests
Total consideration
Cash received
Total consideration, net of cash received
F - 22
$
$
657
4,772
95
27
12
1,139
1,455
8,157
445
3,461
322
4,228
272
3,657
12
3,645
Table of Contents
Index to Financial Statements
Lotus Midstream Acquisition
On May 2, 2023, Energy Transfer acquired Lotus Midstream for total consideration of $1.50 billion, including working capital. Consideration included
$930 million in cash and approximately 44.5 million newly issued Energy Transfer common units, which had an aggregate acquisition-date fair value
of $574 million. Lotus Midstream owns and operates Centurion Pipeline Company LLC, an integrated crude midstream platform located in the
Permian Basin.
The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed:
Total current assets
Property, plant and equipment, net
Investments in unconsolidated affiliates
Lease right-of-use assets, net
Other non-current assets
Intangible assets, net
Total assets
Total current liabilities
Other non-current liabilities
Total liabilities
Total consideration
Cash received
Total consideration, net of cash received
Woodford Express Acquisition
At May 2, 2023
61
1,263
138
10
4
75
1,551
27
16
43
1,508
4
1,504
$
$
On September 13, 2022, Energy Transfer completed the acquisition of 100% of the membership interests in Woodford Express, LLC, which owns a
Midcontinent gas gathering and processing system, for approximately $485 million plus working capital. The system, which is located in the heart of
the SCOOP play, has 450 MMcf/d of cryogenic gas processing and treating capacity and over 200 miles of gathering lines, which are connected to
Energy Transfer’s pipeline network. Woodford Express, LLC repaid aggregate principal of $292 million on its revolving credit facility and term loan
on the closing date of the acquisition, which amount is included in the total consideration.
Energy Transfer Canada Sale
In August 2022, the Partnership completed the sale of its 51% interest in Energy Transfer Canada. The sale resulted in cash proceeds to Energy
Transfer of $302 million.
Energy Transfer Canada’s assets and operations were included in the Partnership’s all other segment until August 2022. Energy Transfer Canada did
not meet the criteria to be reflected as discontinued operations in the Partnership’s consolidated statement of operations. Based on the anticipated
proceeds upon signing of the share purchase agreement in February 2022, during the three months ended March 31, 2022, the Partnership recorded a
write-down on Energy Transfer Canada’s assets of $300 million, of which $164 million was allocated to noncontrolling interests and $136 million was
reflected in net income attributable to partners. Upon the completion of the sale in August 2022, the Partnership recorded an $85 million loss on
deconsolidation.
Spindletop Assets Purchase
In March 2022, the Partnership purchased the membership interests in Caliche Coastal Holdings, LLC (subsequently renamed Energy Transfer
Spindletop LLC), which owns an underground storage facility near Mont Belvieu, Texas, for approximately $325 million.
Enable Acquisition
On December 2, 2021, the Partnership completed the previously announced merger with Enable. Under the terms of the merger agreement, Enable’s
common unitholders received 0.8595 of an Energy Transfer common unit in exchange for each
F - 23
Table of Contents
Index to Financial Statements
Enable common unit. In addition, each outstanding Enable Series A preferred unit was exchanged for 0.0265 of an Energy Transfer Series G Preferred
Unit. A total of 384,780 Series G Preferred Units were issued in connection with the Enable acquisition. The total fair value of Energy Transfer
common units and Series G Preferred Units issued was approximately $3.5 billion at the closing date. Energy Transfer also made a $10 million cash
payment for Enable’s general partner and assumed $3.18 billion aggregate principal amount of Enable senior notes. In addition, Enable’s $800 million
term loan and $35 million revolving credit facility were repaid and terminated in December 2021, immediately subsequent to the close of the Enable
acquisition.
The Enable acquisition was recorded using the acquisition method of accounting, which requires, among other things, that assets acquired and
liabilities assumed be recognized on the balance sheet at their estimated fair values on the date of acquisition with any excess purchase price over the
fair value of net assets acquired recorded to goodwill. Determining the fair value of acquired assets requires management’s judgment and the
utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions. Acquired assets were
valued based on a combination of the discounted cash flow, the guideline company and the reproduction and replacement methods.
The following table summarizes the allocation of the purchase price among the assets acquired and liabilities assumed:
At December 2, 2021
Total current assets
Property, plant and equipment, net
Investments in unconsolidated affiliates
Other non-current assets
Intangible assets, net
Goodwill
Total assets
Total current liabilities
Long-term debt, less current maturities
Other non-current liabilities
Total liabilities
Noncontrolling interests
Total consideration
Cash received
Total consideration, net of cash received
Sunoco LP’s Acquisitions and Divestiture
$
$
593
7,076
40
39
440
138
8,326
488
4,267
18
4,773
34
3,519
61
3,458
On January 22, 2024, Sunoco LP entered into a definitive agreement with NuStar to acquire NuStar in an all-equity transaction valued at
approximately $7.30 billion, including assumed debt. Under the terms of the agreement, NuStar common unitholders will receive 0.4 Sunoco common
units for each NuStar common unit. NuStar has approximately 9,500 miles of pipeline and 63 terminal and storage facilities that store and distribute
crude oil, refined products, renewable fuels, ammonia and specialty liquids. The transaction is expected to close in the second quarter of 2024, subject
to customary closing conditions.
On January 11, 2024, Sunoco LP entered into a definitive agreement with 7-Eleven, Inc. to sell 204 convenience stores located in West Texas, New
Mexico and Oklahoma for approximately $1.00 billion, including customary adjustments for fuel and merchandise inventory. As part of the sale,
Sunoco LP will also amend its existing take-or-pay fuel supply agreement with 7-Eleven, Inc. to incorporate additional fuel gross profit. The
transaction is expected to close promptly upon receipt of regulatory approvals and satisfaction of customary closing conditions.
On January 11, 2024, Sunoco LP also announced that it will acquire liquid fuels terminals in Amsterdam, Netherlands and Bantry Bay, Ireland from
Zenith Energy for €170 million including working capital. The transaction is expected to close in the first quarter of 2024, subject to customary closing
conditions.
F - 24
Table of Contents
Index to Financial Statements
On May 1, 2023, Sunoco LP completed the acquisition of 16 refined product terminals located across the East Coast and Midwest from Zenith Energy
for $111 million, including working capital. The purchase price was primarily allocated to property and equipment.
On November 30, 2022, Sunoco LP completed the acquisition of Peerless Oil & Chemicals, Inc., an established terminal operator that distributes fuel
products to over 100 locations primarily within Puerto Rico, for $67 million, net of cash acquired.
On April 1, 2022, Sunoco LP completed the acquisition of a transmix processing and terminal facility in Huntington, Indiana for $252 million, net of
cash acquired, of which $98 million was allocated to intangible assets, $20 million to goodwill, $73 million to property, plant and equipment and
$76 million to working capital.
4.
INVESTMENTS IN UNCONSOLIDATED AFFILIATES:
Description of Investments
Following is a summary of the Partnership’s significant unconsolidated investees.
Citrus
Energy Transfer owns a 50% interest in Citrus. Citrus owns 100% of FGT, an approximately 5,362-mile natural gas pipeline system that originates in
Texas and delivers natural gas to the Florida peninsula. Our investment in Citrus is reflected in our interstate transportation and storage segment.
MEP
Energy Transfer owns a 50% interest in MEP, which owns the Midcontinent Express Pipeline, an approximately 500-mile natural gas pipeline that
extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental
natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment.
White Cliffs
Energy Transfer owns a 51% interest in White Cliffs, which consists of two parallel, 12-inch common carrier pipelines: one crude oil pipeline and one
NGL pipeline. These pipelines transport crude and NGLs from Platteville, Colorado to Cushing, Oklahoma.
Explorer
Energy Transfer owns a 15% membership interest in Explorer, which consists of a 1,850-mile pipeline which originates from refining centers in
Beaumont, Port Arthur, and Houston, Texas and extends to Chicago, Illinois. Our investment in Explorer is reflected in our NGL and refined products
transportation and services segment.
Summary of Balances Related to Unconsolidated Affiliates
The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2023 and 2022 were as follows:
Citrus
MEP
White Cliffs
Explorer
Other
Total
December 31,
2023
2022
$
$
1,811 $
332
203
67
684
3,097 $
1,800
360
218
69
446
2,893
F - 25
Table of Contents
Index to Financial Statements
The following table presents equity in earnings (losses) of unconsolidated affiliates:
Citrus
MEP
White Cliffs
Explorer
Other
Total equity in earnings of unconsolidated affiliates
Summarized Financial Information
Years Ended December 31,
2022
2021
2023
$
$
146 $
87
10
37
103
383 $
141 $
10
(8)
25
89
257 $
157
(17)
—
24
82
246
The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, Citrus, MEP, White Cliffs
and Explorer (on a 100% basis) for all periods presented:
Current assets
Property, plant and equipment, net
Other assets
Total assets
Current liabilities
Non-current liabilities
Equity
Total liabilities and equity
Revenue
Operating income
Net income
December 31,
2023
2022
$
$
$
$
378 $
7,582
88
8,048 $
260 $
4,379
3,409
8,048 $
Years Ended December 31,
2022
2021
2023
$
1,798 $
1,012
735
1,518 $
704
463
311
7,722
86
8,119
291
4,347
3,481
8,119
1,393
684
446
In addition to the equity method investments described above, we have other equity method investments which are not significant to our consolidated
financial statements.
5. NET INCOME PER COMMON UNIT:
Basic net income per common unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average
number of limited partner interests outstanding. Diluted net income per common unit is computed by dividing net income (as adjusted as discussed
herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. For the diluted
earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from Energy
Transfer’s limited partner unit ownership in Sunoco LP and USAC that would have resulted assuming the incremental units related to Sunoco LP’s and
USAC’s respective long-term incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on
the treasury stock method.
F - 26
Table of Contents
Index to Financial Statements
A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:
2023
Years Ended December 31,
2022
2021
Net income
Less: Net income attributable to redeemable noncontrolling interests
Less: Net income attributable to noncontrolling interests
Net income, net of noncontrolling interests
Less: General Partner’s interest in income
Less: Preferred Unitholders’ interest in income
Common Unitholders’ interest in net income
Basic Income per Common Unit:
Weighted average common units
Basic income per common unit
Diluted Income per Common Unit:
Common Unitholders’ interest in net income
Dilutive effect of equity-based compensation of subsidiaries and distributions to
convertible units
Diluted income available to Common Unitholders
Weighted average common units
Dilutive effect of unvested unit awards
Weighted average common units, assuming dilutive effect of unvested unit
awards
Diluted income per common unit
$
$
$
$
$
$
5,294 $
60
1,299
3,935
3
463
3,469 $
5,868 $
51
1,061
4,756
4
422
4,330 $
3,161.7
3,086.8
1.10 $
1.40 $
3,469 $
4,330 $
(1)
3,468 $
3,161.7
15.5
3,177.2
(2)
4,328 $
3,086.8
10.2
3,097.0
1.09 $
1.40 $
6,687
50
1,167
5,470
6
285
5,179
2,734.4
1.89
5,179
(2)
5,177
2,734.4
5.1
2,739.5
1.89
F - 27
Table of Contents
Index to Financial Statements
6. DEBT OBLIGATIONS:
Our debt obligations consist of the following:
Energy Transfer Indebtedness
(1)
(2)(3)
(2)(3)
(2)(3)
(2)(3)
(1)
(3)
(1)
(1)
(3)
(3)
(1)
3.45% Senior Notes due January 15, 2023
3.60% Senior Notes due February 1, 2023
(1)
4.25% Senior Notes due March 15, 2023
4.25% Senior Notes due March 15, 2023
4.20% Senior Notes due September 15, 2023
(1)
4.50% Senior Notes due November 1, 2023
5.875% Senior Notes due January 15, 2024
5.875% Senior Notes due January 15, 2024
7.60% Senior Notes due February 1, 2024
4.90% Senior Notes due February 1, 2024
7.60% Senior Notes due February 1, 2024
4.25% Senior Notes due April 1, 2024
4.50% Senior Notes due April 15, 2024
(3)
3.90% Senior Notes due May 15, 2024
9.00% Debentures due November 1, 2024
4.05% Senior Notes due March 15, 2025
(4)
5.75% Senior Notes due April 1, 2025
2.90% Senior Notes due May 15, 2025
5.95% Senior Notes due December 1, 2025
4.75% Senior Notes due January 15, 2026
3.90% Senior Notes due July 15, 2026
6.05% Senior Notes due December 1, 2026
4.40% Senior Notes due March 15, 2027
4.20% Senior Notes due April 15, 2027
(4)
6.05% Senior Notes due May 1, 2027
5.50% Senior Notes due June 1, 2027
5.50% Senior Notes due June 1, 2027
4.00% Senior Notes due October 1, 2027
5.55% Senior Notes due February 15, 2028
4.95% Senior Notes due May 15, 2028
4.95% Senior Notes due June 15, 2028
6.10% Senior Notes due December 1, 2028
(4)
6.00% Senior Notes due February 1, 2029
8.00% Senior Notes due April 1, 2029
5.25% Senior Notes due April 15, 2029
7.00% Senior Notes due July 15, 2029
4.15% Senior Notes due September 15, 2029
8.25% Senior Notes due November 15, 2029
8.25% Senior Notes due November 15, 2029
3.75% Senior Note due May 15, 2030
6.40% Senior Notes due December 1, 2030
7.38% Senior Notes due April 1, 2031
5.75% Senior Notes due February 15, 2033
(4)
(4)
December 31,
2023
2022
—
—
—
—
—
—
23
1,127
82
350
—
500
750
600
65
1,000
500
1,000
400
1,000
550
1,000
700
600
600
44
956
750
1,000
800
1,000
500
700
450
1,500
66
547
33
267
1,500
1,000
600
1,500
350
800
5
995
500
600
23
1,127
82
350
277
500
750
600
65
1,000
—
1,000
400
1,000
550
—
700
600
—
44
956
750
1,000
800
1,000
—
—
—
1,500
66
547
33
267
1,500
—
—
1,500
F - 28
Table of Contents
Index to Financial Statements
(5)
4.05% Tax-Exempt Bonds due June 1, 2033
6.55% Senior Notes due December 1,2033
4.90% Senior Notes due March 15, 2035
6.625% Senior Notes due October 15, 2036
5.80% Senior Notes due June 15, 2038
7.50% Senior Notes due July 1, 2038
6.85% Senior Notes due February 15, 2040
6.05% Senior Notes due June 1, 2041
6.50% Senior Notes due February 1, 2042
6.10% Senior Notes due February 15, 2042
4.95% Senior Notes due January 15, 2043
5.15% Senior Notes due February 1, 2043
5.95% Senior Notes due October 1, 2043
5.30% Senior Notes due April 1, 2044
5.00% Senior Notes due May 15, 2044
5.15% Senior Notes due March 15, 2045
5.35% Senior Notes due May 15, 2045
6.125% Senior Notes due December 15, 2045
5.30% Senior Notes due April 15, 2047
5.40% Senior Notes due October 1, 2047
6.00% Senior Notes due June 15, 2048
6.25% Senior Notes due April 15, 2049
5.00% Senior Notes due May 15, 2050
Floating Rate Junior Subordinated Notes due November 1, 2066
Five-Year Credit Facility
Unamortized premiums, discounts and fair value adjustments, net
Deferred debt issuance costs
Subsidiary Indebtedness
Transwestern Debt
5.66% Senior Notes due December 9, 2024
6.16% Senior Notes due May 24, 2037
(3)
Bakken Project Debt
3.90% Senior Notes due April 1, 2024
4.625% Senior Notes due April 1, 2029
Unamortized premiums, discounts and fair value adjustments, net
Deferred debt issuance costs
F - 29
225
1,500
500
400
500
550
250
700
1,000
300
350
450
450
700
531
1,000
800
1,000
900
1,500
1,000
1,750
2,000
600
1,412
128
(197)
44,359
175
75
250
1,000
850
(1)
(4)
1,845
—
—
500
400
500
550
250
700
1,000
300
350
450
450
700
531
1,000
800
1,000
900
1,500
1,000
1,750
2,000
600
793
184
(181)
40,264
175
75
250
1,000
850
(1)
(7)
1,842
Table of Contents
Index to Financial Statements
Sunoco LP Debt
6.00% Senior Notes Due April 15, 2027
5.875% Senior Notes Due March 15, 2028
7.00% Senior Notes due September 25, 2028
4.50% Senior Notes due May 15, 2029
4.50% Senior Notes due April 30, 2030
Sunoco LP Credit Facility due April 7, 2027
Lease-related obligations
Deferred debt issuance costs
USAC Debt
6.875% Senior Notes due April 1, 2026
6.875% Senior Notes due September 1, 2027
(6)
USAC Credit Facility due December 2026
Deferred debt issuance costs
HFOTCO Debt
HFOTCO Tax Exempt Notes due 2050
(5)
Other long-term debt
Total debt
Less: Current maturities of long-term debt
Long-term debt, less current maturities
These notes were redeemed in 2023.
600
400
500
800
800
411
94
(25)
3,580
725
750
872
(11)
2,336
—
—
18
52,388
1,008
51,380 $
$
600
400
—
800
800
900
94
(23)
3,571
725
750
646
(14)
2,107
225
225
3
48,262
2
48,260
These notes were redeemed subsequent to December 31, 2023.
As of December 31, 2023, these notes were classified as long-term as management had the intent and ability to refinance the borrowings on a
long-term basis.
These notes, totaling $2.85 billion aggregate principal amount, were assumed by the Partnership in connection with the closing of the Crestwood
acquisition in November 2023.
In May 2023, the Partnership refinanced all of the $225 million outstanding principal amount of HFOTCO tax-exempt bonds with new 10-year
tax-exempt bonds. The new bonds, which were issued through the Harris County Industrial Development Corporation and are obligations of
Energy Transfer, accrue interest at a fixed rate of 4.05% and are mandatorily redeemable in 2033. Upon redemption, these tax-exempt bonds may
be remarketed on different terms through final maturity of November 1, 2050.
The USAC Credit Facility matures in December 2026, except that if any portion of the 6.875% Senior Notes due 2026 are outstanding on
December 31, 2025, the USAC Credit Facility will mature on December 31, 2025.
F - 30
(1)
(2)
(3)
(4)
(5)
(6)
Table of Contents
Index to Financial Statements
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $237 million in
unamortized premiums, fair value adjustments and deferred debt issuance costs, net:
2024
2025
2026
2027
2028
Thereafter
Total
$
$
4,672
2,900
4,147
6,823
4,200
29,756
52,498
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value
adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap.
Notes and Debentures
Senior Notes
The Energy Transfer Senior Notes are the Partnership’s senior obligations, ranking equally in right of payment with our other existing and future
unsubordinated debt and senior to any of its future subordinated debt. The Energy Transfer Senior Notes are not guaranteed by any of its subsidiaries.
The covenants related to the Energy Transfer Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-
leaseback transactions and limitations on mergers and sales of all or substantially all of the Partnership’s assets.
January 2024 Notes Issuance
In January 2024, the Partnership issued $1.25 billion aggregate principal amount of 5.55% Senior Notes due 2034, $1.75 billion aggregate principal
amount of 5.95% Senior Notes due 2054 and $800 million aggregate principal amount of 8.00% fixed-to-fixed reset rate Junior Subordinated Notes
due 2054. The Partnership used the net proceeds to refinance existing indebtedness, including borrowings under its Five-Year Credit Facility (defined
below), to redeem its outstanding Series C Preferred Units and Series D Preferred Units and for general partnership purposes. The Partnership also
intends to use the proceeds to redeem its Series E Preferred Units in May 2024.
Credit Facilities and Commercial Paper
Five-Year Credit Facility
The Partnership’s Five-Year Credit Facility allows for unsecured borrowings up to $5.00 billion and matures on April 11, 2027. The Five-Year Credit
Facility contains an accordion feature, under which the total aggregate commitment may be increased up to $7.00 billion under certain conditions.
As of December 31, 2023, the Five-Year Credit Facility had $1.41 billion of outstanding borrowings, $1.37 billion of which consisted of commercial
paper. The amount available for future borrowings was $3.56 billion, after accounting for outstanding letters of credit in the amount of $29 million.
The weighted average interest rate on the total amount outstanding as of December 31, 2023 was 5.87%.
Sunoco LP Credit Facility
Sunoco LP maintains a $1.50 billion revolving credit facility (the “Sunoco LP Credit Facility”). As of December 31, 2023, the Sunoco LP Credit
Facility had $411 million of outstanding borrowings and $5 million in standby letters of credit and matures in April 2027. The amount available for
future borrowings was $1.08 billion at December 31, 2023. The weighted average interest rate on the total amount outstanding as of December 31,
2023 was 7.54%.
USAC Credit Facility
USAC maintains a $1.60 billion revolving credit facility (the “USAC Credit Facility”) which matures on December 8, 2026, except that if any portion
of USAC’s senior notes due 2026 are outstanding on December 31, 2025, the USAC Credit Facility will mature on December 31, 2025. As of
December 31, 2023, USAC had $872 million of outstanding borrowings
F - 31
Table of Contents
Index to Financial Statements
and no outstanding letters of credit under the credit agreement. As of December 31, 2023, USAC had $728 million of remaining unused availability of
which, due to restrictions related to compliance with the applicable financial covenants, $529 million was available to be drawn. The weighted average
interest rate on the total amount outstanding as of December 31, 2023 was 7.98%.
Covenants Related to Our Credit Agreements
The agreements relating to the Senior Notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating
agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions.
The Five-Year Credit Facility contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s
subsidiaries’ ability to, among other things:
•
•
•
•
incur indebtedness;
grant liens;
enter into mergers;
dispose of assets;
• make certain investments;
• make Distributions (as defined in the Five-Year Credit Facility) during certain Defaults (as defined in the Five-Year Credit Facility) and during
any Event of Default (as defined in the Five-Year Credit Facility);
•
•
•
engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries;
engage in transactions with affiliates; and
enter into restrictive agreements.
The applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to
our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the Five-Year Credit Facility ranges
from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under
the Five-Year Credit Facility ranges from 0.125% to 0.300%.
The Five-Year Credit Facility contains various covenants including limitations on the creation of indebtedness and liens and related to the operation
and conduct of our business. The Five-Year Credit Facility also limits us, on a rolling four quarter basis, to a maximum Consolidated Funded
Indebtedness to Consolidated EBITDA ratio, as defined in the underlying credit agreement, of 5.00 to 1.00, which can generally be increased to 5.50 to
1.00 during a Specified Acquisition Period. Our Leverage Ratio was 3.31 to 1.00 at December 31, 2023, as calculated in accordance with the credit
agreement.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to
scheduled maturity and could negatively impact the Partnership’s or our subsidiaries’ ability to incur additional debt and/or our ability to pay
distributions to Unitholders.
Covenants Related to Transwestern
The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt,
the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Covenants Related to Sunoco LP
The Sunoco LP Credit Facility contains various customary representations, warranties, covenants and events of default, including a change of control
event of default, as defined therein. Sunoco LP’s Credit Facility requires Sunoco LP to maintain a specified net leverage ratio and interest coverage
ratio.
F - 32
Table of Contents
Index to Financial Statements
Covenants Related to USAC
The USAC Credit Facility contains covenants that limit (subject to certain exceptions) USAC’s ability to, among other things:
•
grant liens;
• make certain loans or investments;
•
•
incur additional indebtedness or guarantee other indebtedness;
enter into transactions with affiliates;
• merge or consolidate;
•
sell our assets; and
• make certain acquisitions.
The USAC Credit Facility is also subject to the following financial covenants, including covenants requiring USAC to maintain:
•
•
•
a minimum EBITDA to interest coverage ratio;
a ratio of total secured indebtedness to EBITDA within a specified range; and
a maximum funded debt to EBITDA ratio.
Compliance with our Covenants
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our
subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our
ability to pay distributions.
We and our subsidiaries were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31,
2023.
7. REDEEMABLE NONCONTROLLING INTERESTS:
Certain redeemable noncontrolling interests in the Partnership’s subsidiaries are reflected as mezzanine equity on the consolidated balance sheet. As of
December 31, 2023 and 2022, redeemable noncontrolling interests included $476 million and $477 million, respectively, related to the USAC
Preferred Units, described below, and $22 million and $16 million, respectively, related to noncontrolling interest holders in one of the Partnership’s
consolidated subsidiaries that have the option to sell their interests to the Partnership. As of December 31, 2023, redeemable noncontrolling interests
also included $280 million related to the Niobrara Preferred Units described below.
USAC Series A Preferred Units
As of December 31, 2023 and 2022, USAC had 500,000 preferred units issued and outstanding. The USAC Preferred Units are entitled to receive
cumulative quarterly distributions equal to $24.375 per USAC Preferred Unit, subject to increase in certain limited circumstances. The USAC
Preferred Units will have a perpetual term, unless converted or redeemed. Certain portions of the USAC Preferred Units are convertible into USAC
common units at the election of the holders. The USAC Preferred Units are convertible, at the option of the holder, into a maximum of 24,985,633
USAC common units in the aggregate. USAC has the option to redeem all or any portion of the USAC Preferred Units then outstanding, subject to
certain minimum redemption threshold amounts, for a redemption price set forth in USAC’s partnership agreement. In addition, beginning April 2028,
the holders of the USAC Preferred Units will have the right to require USAC to redeem all or any portion of the USAC Preferred Units, and USAC
may elect to pay up to 50% of such redemption amount in USAC common units.
On January 12, 2024, the holders of the USAC Preferred Units elected to convert 40,000 USAC Preferred Units into 1,998,850 USAC common units.
Niobrara Preferred Units
Crestwood Niobrara LLC (“Crestwood Niobrara”), a subsidiary acquired in the Crestwood acquisition in November 2023, has outstanding two series
of preferred units (collectively, the “Niobrara Preferred Units”) held by a third party. The Niobrara Preferred Units are redeemable by the Partnership
or the preferred interest holder and are also convertible by the
F - 33
Table of Contents
Index to Financial Statements
preferred interest holder into Crestwood Niobrara common units. The preferred interest holder also has the option to contribute additional capital to
Crestwood Niobrara to increase their common ownership percentage in Crestwood Niobrara to 50% upon the conversion.
8. EQUITY:
Limited Partners
Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the
Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for
trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In
addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all
Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when
sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for
other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described at “Quarterly
Distributions of Available Cash.”
Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the
partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner (which
currently holds an approximately 0.1% general partner interest) until the aggregate amount of net profits for the current and all prior fiscal years equals
the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated
to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net
losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership
Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining
net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General
Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.
Common Units
The change in Energy Transfer Common Units during the years ended December 31, 2023, 2022 and 2021 was as follows:
Number of Common Units, beginning of period
Common Units issued in mergers and acquisitions
Common Units repurchased
Issuance of Common Units
(2)
(1)
Number of Common Units, end of period
2023
Years Ended December 31,
2022
2021
3,094.4
260.2
—
12.9
3,367.5
3,082.5
—
—
11.9
3,094.4
2,702.4
374.6
(4.2)
9.7
3,082.5
(1)
(2)
Common units issued related to our acquisitions of Crestwood and Lotus Midstream in 2023 and of Enable in 2021.
Includes common units issued in connection with the distribution reinvestment program and restricted unit vestings.
Energy Transfer Class A Units
As of December 31, 2023, the Partnership had outstanding 833,486,004 Class A units (“Energy Transfer Class A Units”) representing limited partner
interests in the Partnership to the General Partner. The Energy Transfer Class A Units are entitled to vote together with the Partnership’s common
units, as a single class, except as required by law. Additionally, Energy Transfer’s Partnership Agreement provides that, under certain circumstances,
upon the issuance by the Partnership of additional common units or any securities that have voting rights that are pari passu with the Partnership
common units, the Partnership will issue to any holder of Energy Transfer Class A Units additional Energy Transfer Class A Units such that the holder
maintains a voting interest in the Partnership that is identical to its voting interest in the Partnership prior to such issuance. The Energy Transfer Class
A Units are not entitled to distributions and otherwise have no economic attributes.
F - 34
Table of Contents
Index to Financial Statements
Energy Transfer Repurchase Program
In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $2 billion of Energy
Transfer Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with
applicable regulatory requirements. The Partnership did not repurchase any Energy Transfer Common Units under this program in 2023 or 2022. As of
December 31, 2023, $880 million remained available to repurchase under the current program.
Energy Transfer Distribution Reinvestment Program
During the year ended December 31, 2023, distributions of $90 million were reinvested under the distribution reinvestment program. As of
December 31, 2023, a total of 4.5 million common units remain available to be issued under the existing registration statement in connection with the
distribution reinvestment program.
Energy Transfer Preferred Units
As of December 31, 2023, Energy Transfer’s outstanding preferred units included 950,000 Series A Preferred Units, 550,000 Series B Preferred Units,
18,000,000 Series C Preferred Units, 17,800,000 Series D Preferred Units, 32,000,000 Series E Preferred Units, 500,000 Series F Preferred Units,
1,484,780 Series G Preferred Units, 900,000 Series H Preferred Units and 41,464,179 Series I Preferred Units.
The following table summarizes changes in the Energy Transfer Preferred Units:
Series A
Series B
Series C
Series D
Series E
Series F
Series G
Series H
Series I
Total
—
$
—
$
—
$
—
$
— $
—
$
—
$
—
$
—
$
—
Preferred Unitholders
Balance, December 31, 2020 $
Preferred units conversion
(1)
Units issued for cash
Distributions to partners
Units issued in Enable
acquisition
Other, net
Net income
Balance, December 31, 2021
Distributions to partners
Net income
Balance, December 31, 2022
Distributions to partners
Units issued in Crestwood
acquisition
Net income
943
—
(30)
—
—
45
958
(59)
59
958
(96)
—
86
547
—
(18)
—
—
27
556
(36)
36
556
(36)
—
36
440
—
(25)
—
—
25
440
(33)
33
440
(40)
—
38
434
—
(25)
—
—
25
434
(34)
34
434
(36)
—
37
786
—
(45)
—
—
45
786
(61)
61
786
(61)
—
61
504
—
(34)
—
—
26
496
(34)
34
496
(34)
—
34
1,114
—
(79)
392
—
61
1,488
(106)
106
1,488
(106)
—
106
—
889
(24)
—
(3)
31
893
(59)
59
893
(59)
—
59
Balance, December 31, 2023 $
948
$
556
$
438
$
435
$
786 $
496
$
1,488
$
893
$
—
—
—
—
—
—
—
—
—
—
—
413
6
419
4,768
889
(280)
392
(3)
285
6,051
(422)
422
6,051
(468)
413
463
$
6,459
(1)
In connection with the Rollup Mergers on April 1, 2021, as discussed in Note 1, all of ETO’s previously outstanding preferred units were
converted to Energy Transfer Preferred Units with identical distribution and redemption rights.
Series A Preferred Units
Prior to February 15, 2023, distributions on the Series A Preferred Units accrued at a fixed rate of 6.250% per annum of the liquidation preference of
$1,000. Beginning February 15, 2023 to, but excluding, August 15, 2023, the Series A Preferred Units accrued a floating distribution rate set each
quarterly distribution period at a percentage of the $1,000 liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.028%
per annum. On and after August 15, 2023, the floating distribution rate on the Series A Preferred Units is based on the three-month SOFR, plus a tenor
spread adjustment of 0.26161%, plus 4.028% per annum. Distributions on the Series A Preferred Units were previously payable
F - 35
Table of Contents
Index to Financial Statements
semiannually in arrears until February 15, 2023, and, after February 15, 2023, quarterly in arrears, when, as, and if declared by our General Partner out
of legally available funds for such purpose.
Series B Preferred Units
Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February
15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B
Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, or a
successor rate, in each case determined quarterly by our calculation agent, plus a spread of 4.155% per annum. The Series B Preferred Units are
redeemable at Energy Transfer’s option on or after February 15, 2028 at a redemption price of $1,000 per Series B Preferred Unit, plus an amount
equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series C Preferred Units
Prior to May 15, 2023, distributions on the Series C Preferred Units accrued at a fixed rate of 7.375% per annum of the liquidation preference of $25.
Beginning May 15, 2023 to, but excluding, August 15, 2023, the Series C Preferred Units accrued a floating distribution rate set each quarterly
distribution period at a percentage of the $25 liquidation preference equal to the then-current three-month LIBOR plus a spread of 4.530% per annum.
On and after August 15, 2023, the floating distribution rate on the Series C Preferred Units based on the three-month SOFR, plus a tenor spread
adjustment of 0.26161%, plus 4.530% per annum. The Series C Preferred Units were redeemed in February 2024.
Series D Preferred Units
Prior to August 15, 2023, distributions on the Series D Preferred Units accrued at a fixed rate of 7.625% per annum of the liquidation preference of
$25. On and after August 15, 2023, the Series D Preferred Units accrued a floating distribution rate set each quarterly distribution period at a
percentage of the $25 liquidation preference equal to the three-month SOFR, plus a tenor spread adjustment of 0.26161%, plus 4.738% per annum. The
Series D Preferred Units were redeemed in February 2024.
Series E Preferred Units
Distributions on the Series E Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, May 15,
2024, at a rate of 7.600% per annum of the stated liquidation preference of $25. On and after May 15, 2024, distributions on the Series E Preferred
Units will accumulate at a percentage of the $25 liquidation preference equal to an annual floating rate of the three-month LIBOR, or a successor rate,
in each case determined quarterly by our calculation agent, plus a spread of 5.161% per annum. The Series E Preferred Units are redeemable at Energy
Transfer’s option on or after May 15, 2024 at a redemption price of $25 per Series E Preferred Unit, plus an amount equal to all accumulated and
unpaid distributions thereon to, but excluding, the date of redemption. The Partnership intends to redeem the Series E Preferred Units in May 2024.
Series F Preferred Units
Distributions on the Series F Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on
the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2025, at a rate equal to 6.750% per annum
of the $1,000 liquidation preference. On and after May 15, 2025, the distribution rate on the Series F Preferred Units will equal a percentage of the
$1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.134% per annum. The Series F Preferred Units are redeemable
at Energy Transfer’s option on or after May 15, 2025 at a redemption price of $1,000 per Series F Preferred Unit, plus an amount equal to all
accumulated and unpaid distributions thereon to, but excluding, the date of redemption.
Series G Preferred Units
Distributions on the Series G Preferred Units are cumulative from and including the original issue date and will be payable semi-annually in arrears on
the 15th day of May and November of each year, commencing on May 15, 2020 to, but excluding, May 15, 2030, at a rate equal to 7.125% per annum
of the $1,000 liquidation preference. On and after May 15, 2030, the distribution rate on the Series G Preferred Units will equal a percentage of the
$1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.306% per annum. The Series G Preferred Units are
redeemable at Energy Transfer’s option on or after May 15, 2030 at a redemption price of $1,000 per Series G Preferred Unit, plus an amount equal to
all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. On December
F - 36
Table of Contents
Index to Financial Statements
2, 2021, Energy Transfer issued 384,780 Series G Preferred Units in connection with the Enable acquisition, as discussed in Note 3.
Series H Preferred Units
On June 15, 2021, Energy Transfer issued 900,000 of its 6.500% Series H Preferred Units at a price to the public of $1,000 per unit. Distributions on
the Series H Preferred Units will accrue and be cumulative to, but excluding, November 15, 2026, at a rate equal to 6.500% per annum of the $1,000
liquidation preference. On and after November 15, 2026 and each fifth anniversary thereafter, the distribution rate on the Series H Preferred Units will
reset to be a percentage of the $1,000 liquidation preference equal to the five-year U.S. treasury rate plus a spread of 5.694% per annum. Distributions
on the Series H Preferred Units will be payable semi-annually in arrears on the 15th day of May and November of each year. The Series H Preferred
Units are redeemable at Energy Transfer’s option during the three-month period prior to, and including, each distribution reset date at a redemption
price of $1,000 per Series H Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of
redemption.
Series I Preferred Units
On November 3, 2023, Energy Transfer, in connection with its acquisition of Crestwood, issued 41,464,179 of its Series I Preferred Units in exchange
for a commensurate number of Crestwood preferred units. Subject to certain conditions, the holders of the Series I Preferred Units will have the right
to convert preferred units into (i) common units on a 10-for-2.07 basis, or (ii) a number of common units determined pursuant to a conversion ratio set
forth in the Partnership Agreement upon the occurrence of certain events, such as a change in control. The Series I Preferred Units, on an as converted
basis, have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, except that
the preferred units are entitled to vote as a separate class on any matter on which all unitholders are entitled to vote that adversely affects the rights,
powers, privileges or preferences of the preferred units in relation to Energy Transfer’s other securities outstanding
The holders of the Series I Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Distributions on the preferred units
are paid in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined
in our Partnership Agreement) is insufficient to make a cash distribution to Series I Preferred Unitholders.
Upcoming Changes in Preferred Unit Distribution Rates
Distributions on the Energy Transfer Series B Preferred Units and Series E Preferred Units are scheduled to begin accruing at a floating rate as follows:
Beginning of floating rate
period
Series B Preferred Units
Series E Preferred Units
February 15, 2028
May 15, 2024
Applicable Spread
Tenor spread adjustment
4.155 %
5.161 %
0.26161 %
0.26161 %
Floating rate
Three-month SOFR
Three-month SOFR
As discussed above, the Partnership expects to redeem the Series E Preferred Units at the beginning of the floating rate period on May 15, 2024.
Sale of Common Units by Subsidiaries
Energy Transfer on a stand-alone basis (the “Parent Company”) accounts for the difference between the carrying amount of its investment in
subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital
transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the
investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any
impairment related to the issuances of subsidiary common units during the periods presented.
Subsidiary Equity Transactions
USAC’s Distribution Reinvestment Program
During the years ended December 31, 2023, 2022 and 2021, USAC issued 87,808, 124,255 and 118,399 USAC common units, respectively, under the
USAC distribution reinvestment program.
F - 37
Table of Contents
Index to Financial Statements
USAC’s Warrants
In April 2022, USAC issued 534,308 of its common units in connection with the exercise of outstanding warrants. In October 2023, the remainder of
USAC’s outstanding warrants were exercised in full and net settled for 2,360,488 USAC common units. As of December 31, 2023, no warrants are
outstanding.
Energy Transfer Common Unit Distributions
Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly.
Our distributions declared and paid with respect to our common units were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2020
March 31, 2021
June 30, 2021
September 30, 2021
December 31, 2021
March 31, 2022
June 30, 2022
September 30, 2022
December 31, 2022
March 31, 2023
June 30, 2023
September 30, 2023
December 31, 2023
February 8, 2021
May 11, 2021
August 6, 2021
November 5, 2021
February 8, 2022
May 9, 2022
August 8, 2022
November 4, 2022
February 7, 2023
May 8, 2023
August 14, 2023
October 30, 2023
February 7, 2024
February 19, 2021
May 19, 2021
August 19, 2021
November 19, 2021
February 18, 2022
May 19, 2022
August 19, 2022
November 21, 2022
February 21, 2023
May 22, 2023
August 21, 2023
November 20, 2023
February 20, 2024
0.1525
0.1525
0.1525
0.1525
0.1750
0.2000
0.2300
0.2650
0.3050
0.3075
0.3100
0.3125
0.3150
Energy Transfer Preferred Unit Distributions
Distributions on Energy Transfer’s preferred units declared and/or paid by Energy Transfer were as follows:
Period Ended
Record Date
Payment Date
Series A
(1)
Series B
(1)
Series C
Series D
Series E
Series F
(1)
Series G
(1)
Series H
(1)
Series I
March 31,
2021
June 30, 2021
September
30, 2021
December 31,
2021
March 31,
2022
June 30, 2022
September
30, 2022
December 31,
2022
March 31,
2023
June 30, 2023
September
30, 2023
December 31,
2023
May 3, 2021
August 2,
2021
November 1,
2021
February 1,
2022
May 2, 2022
August 1,
2022
November 1,
2022
February 1,
2023
May 1, 2023
August 1,
2023
November 1,
2023
February 1,
2024
May 17, 2021
August 16,
2021
November 15,
2021
February 15,
2022
May 16, 2022
August 15,
2022
November 15,
2022
February 15,
2023
May 15, 2023
August 15,
2023
November 15,
2023
February 15,
2024
*
Represents prorated initial distribution.
—
31.25
21.98
23.89
24.67
24.71
$—
$—
$0.4609
$0.4766
$0.4750
$33.7500
$35.63
31.25
33.125
0.4609
0.4766
0.4750
—
—
$—
—
—
—
0.4609
0.4766
0.4750
33.7500
35.63
27.08
*
31.25
33.125
0.4609
0.4766
0.4750
—
—
—
—
—
0.4609
0.4766
0.4750
33.7500
35.63
32.50
31.25
33.125
0.4609
0.4766
0.4750
—
—
—
—
0.4609
0.4766
0.4750
33.7500
35.63
32.50
33.125
0.4609
0.4766
0.4750
—
—
—
—
0.4609
0.4766
0.4750
33.7500
35.63
32.50
33.125
0.6294
0.4766
0.4750
—
—
—
—
0.6489
0.6622
0.4750
33.7500
35.63
32.50
33.125
0.6075
0.6199
0.4750
—
—
—
0.2111
F - 38
$—
—
—
—
—
—
—
—
—
—
—
Table of Contents
Index to Financial Statements
(1)
Series B, Series F, Series G and Series H distributions are currently paid on a semi-annual basis. Pursuant to their terms, distributions on the Series
A preferred units began to be paid quarterly on February 15, 2023, and distributions on the Series B preferred units will begin to be paid quarterly
on February 15, 2028.
Sunoco LP Cash Distributions
Energy Transfer owns approximately 28.5 million Sunoco LP common units and all of Sunoco LP’s IDRs. As of December 31, 2023, Sunoco LP had
approximately 84.4 million common units outstanding.
The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the
holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth
under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash
from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit
target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to
quarterly distribution amounts that are less than the minimum quarterly distribution.
Minimum Quarterly Distribution
First Target Distribution
Second Target Distribution
Third Target Distribution
Thereafter
Total Quarterly Distribution Target Amount
$0.4375
$0.4375 to $0.503125
$0.503125 to $0.546875
$0.546875 to $0.656250
Above $0.656250
Distributions on Sunoco LP’s units declared and/or paid by Sunoco LP were as follows:
Marginal Percentage Interest in
Distributions
Common
Unitholders
100%
100%
85%
75%
50%
Holder of IDRs
—%
—%
15%
25%
50%
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2020
March 31, 2021
June 30, 2021
September 30, 2021
December 31, 2021
March 31, 2022
June 30, 2022
September 30, 2022
December 31, 2022
March 31, 2023
June 30, 2023
September 30, 2023
December 31, 2023
USAC Cash Distributions
February 8, 2021
May 11, 2021
August 6, 2021
November 5, 2021
February 8, 2022
May 9, 2022
August 8, 2022
November 4, 2022
February 7, 2023
May 8, 2023
August 14, 2023
October 30, 2023
February 7, 2024
February 19, 2021
May 19, 2021
August 19, 2021
November 19, 2021
February 18, 2022
May 19, 2022
August 19, 2022
November 18, 2022
February 21, 2023
May 22, 2023
August 21, 2023
November 20, 2023
February 20, 2024
0.8255
0.8255
0.8255
0.8255
0.8255
0.8255
0.8255
0.8255
0.8255
0.8420
0.8420
0.8420
0.8420
Energy Transfer owns approximately 46.1 million USAC common units. As of December 31, 2023, USAC had approximately 101.0 million common
units outstanding. USAC currently has a non-economic general partner interest and no outstanding IDRs.
F - 39
Table of Contents
Index to Financial Statements
Distributions on USAC’s units declared and/or paid by USAC were as follows:
Quarter Ended
Record Date
Payment Date
Rate
December 31, 2020
March 31, 2021
June 30, 2021
September 30, 2021
December 31, 2021
March 31, 2022
June 30, 2022
September 30, 2022
December 31, 2022
March 31, 2023
June 30, 2023
September 30, 2023
December 31, 2023
January 25, 2021
April 26, 2021
July 26, 2021
October 25, 2021
January 24, 2022
April 25, 2022
July 25, 2022
October 24, 2022
January 23, 2023
April 24, 2023
July 24, 2023
October 23, 2023
January 22, 2024
February 5, 2021
May 7, 2021
August 6, 2021
November 5, 2021
February 4, 2022
May 6, 2022
August 5, 2022
November 4, 2022
February 3, 2023
May 5, 2023
August 4, 2023
November 3, 2023
February 2, 2024
Accumulated Other Comprehensive Income
The following table presents the components of AOCI, net of tax:
Available-for-sale securities
Foreign currency translation adjustment
Actuarial gain (loss) related to pensions and other postretirement benefits
Investments in unconsolidated affiliates, net
Total AOCI, net of tax
December 31,
2023
2022
$
$
13 $
(5)
6
14
28 $
The following table sets forth the tax amounts included in the respective components of other comprehensive income:
Available-for-sale securities
Foreign currency translation adjustment
Actuarial loss relating to pension and other postretirement benefits
Total
9. EQUITY INCENTIVE PLANS:
December 31,
2023
2022
$
$
(3) $
6
—
3 $
We, Sunoco LP and USAC, have issued equity incentive plans for employees, officers and directors, which provide for various types of awards,
including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation
rights, cash restricted units and other equity-based compensation awards. As of December 31, 2023, an aggregate total of 42.9 million Energy Transfer
Common Units remain available to be awarded under our equity incentive plans.
Energy Transfer Long-Term Incentive Plan
We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with
vesting based on continued employment as of each applicable vesting date. Upon vesting, Energy Transfer Common Units are issued. These unit
awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been
forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such
distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee
directors each receive grants with a five-year service vesting requirement.
F - 40
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
0.5250
9
1
(7)
13
16
1
6
1
8
Table of Contents
Index to Financial Statements
The following table shows the activity of the awards granted to employees and non-employee directors:
Unvested awards as of December 31, 2022
Awards granted
Awards vested
Awards forfeited
Unvested awards as of December 31, 2023
Number of Units
Weighted Average Grant-
Date Fair Value Per Unit
37.7 $
10.7
(7.7)
(1.6)
39.1 $
9.62
13.78
9.22
9.52
10.84
During the years ended December 31, 2023, 2022, and 2021, the weighted average grant-date fair value per unit award granted was $13.78, $11.56 and
$8.46, respectively, and the total fair value of awards vested was $106 million, $103 million and $52 million, respectively, based on the market price of
the respective Common Units as of the vesting date. As of December 31, 2023, a total of 39.1 million unit awards remain unvested, for which Energy
Transfer expects to recognize a total of $279 million in compensation expense over a weighted average period of 3.0 years.
Cash Restricted Units. The Partnership has also granted cash restricted units, which vest through three years of service. A cash restricted unit entitles
the award recipient to receive cash equal to the market value of one Energy Transfer Common Unit upon vesting. For the years ended December 31,
2023, 2022 and 2021, the Partnership granted a total of 3.2 million, 3.8 million and 3.9 million cash restricted units, respectively. As of December 31,
2023, a total of 6.9 million cash restricted units were unvested. As of December 31, 2023, the Partnership’s consolidated balance sheet reflected
aggregate liabilities of $3.0 million related to cash restricted units.
Subsidiary Long-Term Incentive Plans
Each of Sunoco LP and USAC has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards”) to employees and directors
that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s
compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of
the Subsidiary Unit Awards are time-vested grants, which generally vest over a three or five-year period, that entitles the grantees of the unit awards to
receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is
outstanding.
The following table summarizes the activity of the Subsidiary Unit Awards:
Unvested awards as of December 31, 2022
Awards granted
Awards vested
Awards forfeited
Unvested awards as of December 31, 2023
Sunoco LP
USAC
Weighted
Average
Grant-Date Fair
Value
Per Unit
Number of
Units
Number of
Units
Weighted
Average
Grant-Date Fair
Value
Per Unit
1.8 $
0.4
(0.6)
—
1.6 $
34.29
53.37
28.35
34.64
41.08
2.1 $
0.5
(0.6)
(0.1)
1.9 $
14.21
23.13
13.29
17.50
17.08
The following table summarizes the weighted average grant-date fair value per unit award granted:
Sunoco LP
USAC
Years Ended December 31,
2022
2021
2023
$
53.37 $
23.13
43.54 $
18.31
37.72
14.92
The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2023, 2022 and 2021 was $37 million, $26 million and
$24 million, respectively, based on the market price of Sunoco LP and USAC common units as of the vesting date. As of December 31, 2023,
estimated compensation cost related to Subsidiary Unit Awards not yet
F - 41
Table of Contents
Index to Financial Statements
recognized was $55 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.5 years.
10. INCOME TAXES:
As a partnership, we are not subject to United States federal income tax and most state income taxes. However, the Partnership conducts certain
activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax
expense (benefit) of our taxable subsidiaries are summarized as follows:
Current expense:
Federal
State
Total
Deferred expense (benefit):
Federal
State
Foreign
Total
Total income tax expense
Years Ended December 31,
2022
2021
2023
$
$
56 $
44
100
227
(24)
—
203
303 $
— $
17
17
239
(58)
6
187
204 $
19
24
43
246
(106)
1
141
184
Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to United States federal
and most state income taxes at the partnership level. A reconciliation of income tax expense at the United States statutory rate to the Partnership’s
income tax benefit for the years ended December 31, 2023, 2022 and 2021 is as follows:
Income tax expense at United States statutory rate
$
1,175 $
1,275 $
1,443
Years Ended December 31,
2022
2021
2023
Increase (reduction) in income taxes resulting from:
Partnership earnings not subject to tax
Noncontrolling interests
State tax, net of federal tax benefit
Statutory rate change
Valuation allowance
Uncertain tax positions
Dividend received deduction
Foreign taxes
Other
Income tax expense
(884)
—
47
(10)
(3)
(14)
(3)
—
(5)
303 $
(1,086)
26
19
(42)
(4)
(3)
(3)
6
16
204 $
(1,211)
—
85
(46)
(63)
(34)
(4)
1
13
184
$
F - 42
Table of Contents
Index to Financial Statements
Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities.
The following table summarizes the principal components of the deferred tax assets (liabilities) as follows:
Deferred income tax assets:
Net operating losses and other carryforwards
Other
Total deferred income tax assets
Valuation allowance
Net deferred income tax assets
Deferred income tax liabilities:
Property, plant and equipment
Investments in affiliates
Trademarks
Other
Total deferred income tax liabilities
Net deferred income taxes
December 31,
2023
2022
$
$
371 $
46
417
—
417
(232)
(4,003)
(91)
(22)
(4,348)
(3,931) $
603
60
663
(19)
644
(218)
(4,010)
(89)
(28)
(4,345)
(3,701)
As of December 31, 2023, ETP Holdco had a federal net operating loss carryforward of $1.4 billion, that can be carried forward indefinitely. A total of
$341 million of the federal net operating loss carryforward is limited under IRC §382. Although we expect to fully utilize the IRC §382 limited federal
net operating loss, the amount utilized in a particular year may be limited. As of December 31, 2023, Sunoco Retail LLC, a corporate subsidiary of
Sunoco LP, had a state net operating loss carryforward of $75 million, which we expect to fully utilize. Sunoco Retail LLC has no federal net operating
loss carryforward.
Our corporate subsidiaries have state net operating loss carryforward benefits of $75 million, net of federal tax, some of which expire between 2024
and 2042, while others are carried forward indefinitely. Our corporate subsidiaries have cumulative excess business interest expense of $136 million
available for carryforward indefinitely, of which $23 million is limited under IRC §382.
The following table sets forth the changes in unrecognized tax benefits:
Balance at beginning of year
Reduction attributable to tax positions taken in prior years
Settlements
Balance at end of year
2023
Years Ended December 31,
2022
2021
$
$
52 $
(9)
(3)
40 $
56 $
(4)
—
52 $
90
(34)
—
56
As of December 31, 2023, we had $40 million ($38 million after federal income tax benefits) related to tax positions which, if recognized, would
impact our effective tax rate.
Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During
2023, we recognized an interest and penalty benefit of $7 million. At December 31, 2023, we have interest and penalties accrued of $11 million, net of
tax.
In November 2015, the Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”) that the
Pennsylvania limitation on NOL carryforward deductions violated the uniformity clause of the Pennsylvania Constitution and struck the NOL
limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision with respect to the uniformity clause violation;
however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact.
Nextel subsequently filed a petition for writ of certiorari with the United States Supreme Court, and this was denied on June 11, 2018. Certain
Pennsylvania taxpayers have subsequently undertaken litigation in Pennsylvania state courts on issues not addressed by the
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Pennsylvania Supreme Court in Nextel, specifically, whether the Due Process and Equal Protection Clauses of the United States Constitution and the
Remedies Clause of the Pennsylvania Constitution require a court to grant the taxpayer relief. On December 22, 2021, the Pennsylvania Supreme
Court found in General Motors Corporation v. Commonwealth (“GM”) that the taxpayer was entitled to meaningful backwards looking relief under the
Due Process Clause, meaning the Commonwealth must equalize the taxpayer’s position with taxpayers who were not affected by the NOL cap in place
for the year at issue. The Court therefore held the taxpayer was entitled to a refund by calculating its tax for that year with an uncapped NOL
deduction. We believe the Pennsylvania Supreme Court’s ruling in GM will more likely than not be upheld if challenged by the Commonwealth. ETC
Sunoco previously recognized approximately $67 million ($53 million after federal income tax benefits) in tax benefit based on previously filed tax
returns and certain previously filed protective claims as relates to its cases currently held pending the Nextel matter. In addition, based upon the
Pennsylvania Supreme Court’s October 2017 decision, and because of uncertainty in the breadth of the application of the decision, ETC Sunoco
previously reserved $34 million ($27 million after federal income tax benefits) against the receivable. Subsequent to the Pennsylvania Supreme Court’s
decision in GM, the reserve has been reversed and the entire tax benefit of $34 million ($27 million after federal income tax benefit) has been
recognized by the Partnership.
The Partnership’s 2020 U.S. Federal income tax return is currently under examination by the Internal Revenue Service. The IRS is auditing
Crestwood’s 2020 U.S. Federal income tax return. In general, Energy Transfer and its subsidiaries are no longer subject to examination by the IRS, and
most state jurisdictions, for the 2018 and prior tax years.
USAC is currently under examination by the IRS for years 2019 and 2020. Energy Transfer and its other subsidiaries also have various state and local
income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized
tax benefits have been recorded for any potential assessment with respect to these examinations.
11. REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES:
FERC Proceedings
Rover – FERC - Stoneman House
In late 2016, FERC Enforcement Staff began a non-public investigation related to Rover’s purchase and removal of a potentially historic home (known
as the Stoneman House) while Rover’s application for permission to construct the new 711-mile interstate natural gas pipeline and related facilities was
pending. On March 18, 2021, FERC issued an Order to Show Cause and Notice of Proposed Penalty (Docket No. IN19-4-000), ordering Rover to
explain why it should not pay a $20 million civil penalty for alleged violations of FERC regulations requiring certificate holders to be forthright in
their submissions of information to the FERC. Rover filed its answer and denial to the order on June 21, 2021 and a surreply on September 15, 2021.
FERC issued an order on January 20, 2022 setting the matter for hearing before an administrative law judge. The hearing was set to commence on
March 6, 2023; as explained below, this FERC proceeding has been stayed.
On February 1, 2022, Energy Transfer and Rover filed a Complaint for Declaratory Relief in the United States District Court for the Northern District
of Texas (“Federal District Court”) seeking an order declaring that FERC must bring its enforcement action in federal district court (instead of before
an administrative law judge). Also on February 1, 2022, Energy Transfer and Rover filed an expedited request to stay the proceedings before the FERC
administrative law judge pending the outcome of the Federal District Court case. On May 24, 2022, the Federal District Court ordered a stay of the
FERC’s enforcement case and the District Court case pending the resolution of two cases pending before the United States Supreme Court. Arguments
were heard in those cases on November 7, 2022. On April 14, 2023, the United States Supreme Court held against the government in both cases,
finding that the federal district courts had jurisdiction to hear those suits and to resolve the parties’ constitutional challenges. The cases were remanded
to the federal district courts for further proceedings.
On September 13, 2023 the District Court ordered that the District Court case would be stayed pending the resolution of another case pending before
the United States Supreme Court and that the FERC enforcement case would remain stayed. Energy Transfer and Rover intend to vigorously defend
this claim. On November 13, 2023, the FERC appealed the District Court order to the United States Court of Appeals for the Fifth Circuit. On
December 11, 2023, FERC filed a motion to withdraw that appeal, which the Fifth Circuit granted on December 12, 2023. The FERC and District
Court proceedings remain stayed pending resolution of the case pending before the United States Supreme Court. A decision on that Supreme Court
case is expected by June 2024.
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Rover – FERC - Tuscarawas
In mid-2017, FERC Enforcement Staff began a non-public investigation regarding allegations that diesel fuel may have been included in the drilling
mud at the Tuscarawas River horizontal directional drilling (“HDD”) operations. Rover and the Partnership are cooperating with the investigation. In
2019, Enforcement Staff provided Rover with a notice pursuant to Section 1b.19 of the FERC regulations that Enforcement Staff intended to
recommend that the FERC pursue an enforcement action against Rover and the Partnership. On December 16, 2021, FERC issued an Order to Show
Cause and Notice of Proposed Penalty (Docket No. IN17-4-000), ordering Rover and Energy Transfer to show cause why they should not be found to
have violated Section 7(e) of the NGA, Section 157.20 of FERC’s regulations, and the Rover Pipeline Certificate Order, and assessed civil penalties of
$40 million.
Rover and Energy Transfer filed their answer to this order on March 21, 2022, and Enforcement Staff filed a reply on April 20, 2022. Rover and
Energy Transfer filed their surreply to this order on May 13, 2022. FERC has taken no further action on the case since that time. The primary
contractor (and one of the subcontractors) responsible for the HDD operations of the Tuscarawas River site have agreed to indemnify Rover and the
Partnership for any and all losses, including any fines and penalties from government agencies, resulting from their actions in conducting such HDD
operations. Given the stage of the proceedings, the Partnership is unable at this time to provide an assessment of the potential outcome or range of
potential liability, if any; however, the Partnership believes the indemnity described above will be applicable to the penalty proposed by Enforcement
Staff and intends to vigorously defend itself against the subject claims.
Other FERC Proceedings
By an order issued on January 16, 2019, the FERC initiated a review of Panhandle’s then existing rates pursuant to Section 5 of the NGA to determine
whether the rates charged by Panhandle are just and reasonable and set the matter for hearing. On August 30, 2019, Panhandle filed a general rate
proceeding under Section 4 of the NGA. The NGA Section 5 and Section 4 proceedings were consolidated by order of the Chief Judge on October 1,
2019. The initial decision by the administrative law judge was issued on March 26, 2021, and on December 16, 2022, the FERC issued its order on the
initial decision. On January 17, 2023, Panhandle and the Michigan Public Service Commission each filed a request for rehearing of FERC’s order on
the initial decision, which were denied by operation of law as of February 17, 2023. On March 23, 2023, Panhandle appealed these orders to the United
States Court of Appeals for the District of Columbia Circuit (“Court of Appeals”), and the Michigan Public Service Commission also subsequently
appealed these orders. On April 25, 2023, the Court of Appeals consolidated Panhandle’s and Michigan Public Service Commission’s appeals and
stayed the consolidated appeal proceeding while the FERC further considered the requests for rehearing of its December 16, 2022 order. On September
25, 2023, the FERC issued its order addressing arguments raised on rehearing and compliance, which denied our requests for rehearing. Panhandle has
timely filed its Petition for Review with the Court of Appeals regarding the September 25, 2023 order. On October 25, 2023, Panhandle filed a limited
request for rehearing of the September 25 order addressing arguments raised on rehearing and compliance, which was subsequently denied by
operation of law on November 27, 2023. On November 30, 2023, Panhandle submitted a refund report regarding the consolidated rate proceedings,
which has been protested by several parties. On January 5, 2024, the FERC issued a second order addressing arguments raised on rehearing in which it
modified certain discussion from its September 25, 2023 order and sustained its prior conclusions. Panhandle has timely filed its Petition for Review
with the Court of Appeals regarding the January 5, 2024 order.
On December 1, 2022, Sea Robin filed a rate case pursuant to Section 4 of the NGA. By order dated June 29, 2023, a revised procedural schedule was
adopted in this proceeding setting the commencement of the hearing for January 9, 2024, with an initial decision anticipated by May 21, 2024.
Subsequently, by Order of the Acting Chief Administrative Law Judge, deadlines in the procedural schedule were extended, including revised hearing
commencement and initial decisions deadlines to March 26, 2024 and August 8, 2024, respectively. On November 29, 2023, the parties reached a
settlement in principle and the settlement was filed with the FERC on December 29, 2023.
In May 2021, the FERC commenced an audit of SPLP for the period from January 1, 2018 to present to evaluate SPLP’s compliance with its FERC oil
tariffs, the accounting requirements of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s Form No. 6 reporting
requirements. An audit report was received in September 2023 noting no issues that would have a material impact on the Partnership's financial
position or results of operations.
Commitments
In the normal course of business, Energy Transfer purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term
transportation and storage agreements. Such contracts contain terms that are customary in the industry. Energy Transfer believes that the terms of these
agreements are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.
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Our joint venture agreements require that we fund our proportionate share of capital contributions to our unconsolidated affiliates. Such contributions
will depend upon the unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable rights-of-way (“ROW”) commitments which require fixed payments and either expire upon our chosen abandonment
or at various dates in the future. The following table reflects ROW expense included in operating expenses in the accompanying consolidated
statements of operations:
ROW expense
Litigation and Contingencies
2023
$
Years Ended December 31,
2022
68 $
64 $
2021
48
We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Due to the flammable
and combustible nature of natural gas and crude oil, the potential exists for personal injury and/or property damage to occur in connection with their
transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits
seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in
amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry.
However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that
such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future.
We or our subsidiaries are parties to various legal proceedings, arbitrations and/or regulatory proceedings incidental to our businesses. For each of
these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable
outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be
estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As new information
becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period.
As of December 31, 2023 and 2022, accruals of approximately $285 million and $200 million, respectively, were reflected on our consolidated balance
sheets related to contingent obligations that met both the probable and reasonably estimable criteria. In addition, we may recognize additional
contingent losses in the future related to (i) contingent matters for which a loss is currently considered reasonably possible but not probable and/or (ii)
losses in excess of amounts that have already been accrued for such contingent matters. In some of these cases, we are not able to estimate possible
losses or a range of possible losses in excess of amounts accrued. For such matters where additional contingent losses can be reasonably estimated, the
range of additional losses is estimated to be up to approximately $200 million.
The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in
the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts or our estimates of reasonably possible
losses prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome.
The following sections include descriptions of certain matters that could impact the Partnership’s financial position, results of operations and/or cash
flows in future periods. The following sections also include updates to certain matters that have previously been disclosed, even if those matters are not
anticipated to have a potentially significant impact on future periods. In addition to the matters disclosed in the following sections, the Partnership is
also involved in multiple other matters that could impact future periods, including other lawsuits and arbitration related to the Partnership’s commercial
agreements. With respect to such matters, contingencies that met both the probable and reasonably estimable criteria have been included in the accruals
disclosed above, and the range of additional losses disclosed above also reflects any relevant amounts for such matters.
Dakota Access Pipeline
On July 27, 2016, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the United States District Court for the District of Columbia (“District
Court”) challenging permits issued by the United States Army Corps of Engineers (“USACE”) that allowed Dakota Access to cross the Missouri River
at Lake Oahe in North Dakota. The case was subsequently amended to challenge an easement issued by the USACE that allowed the pipeline to cross
land owned by the
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USACE adjacent to the Missouri River. Dakota Access and the Cheyenne River Sioux Tribe (“CRST”) intervened. Separate lawsuits filed by the
Oglala Sioux Tribe (“OST”) and the Yankton Sioux Tribe (“YST”) were consolidated with this action and several individual tribal members intervened
(collectively, with SRST and CRST, the “Tribes”). On March 25, 2020, the District Court remanded the case back to the USACE for preparation of an
Environment Impact Statement (“EIS”). On July 6, 2020, the District Court vacated the easement and ordered the Dakota Access Pipeline to be shut
down and emptied of oil by August 5, 2020. Dakota Access and the USACE appealed to the Court of Appeals which granted an administrative stay of
the District Court’s July 6 order and ordered further briefing on whether to fully stay the July 6 order. On August 5, 2020, the Court of Appeals (1)
granted a stay of the portion of the District Court order that required Dakota Access to shut the pipeline down and empty it of oil, (2) denied a motion
to stay the March 25 order pending a decision on the merits by the Court of Appeals as to whether the USACE would be required to prepare an EIS
and (3) denied a motion to stay the District Court’s order to vacate the easement during this appeal process. The August 5 order also states that the
Court of Appeals expected the USACE to clarify its position with respect to whether USACE intended to allow the continued operation of the pipeline
notwithstanding the vacatur of the easement and that the District Court may consider additional relief, if necessary.
On August 10, 2020, the District Court ordered the USACE to submit a status report by August 31, 2020, clarifying its position with regard to its
decision-making process with respect to the continued operation of the pipeline. On August 31, 2020, the USACE submitted a status report that
indicated that it considered the presence of the pipeline at the Lake Oahe crossing without an easement to constitute an encroachment on federal land,
and that it was still considering whether to exercise its enforcement discretion regarding this encroachment. The Tribes subsequently filed a motion
seeking an injunction to stop the operation of the pipeline and both USACE and Dakota Access filed briefs in opposition of the motion for injunction.
The motion for injunction was fully briefed as of January 8, 2021.
On January 26, 2021, the Court of Appeals affirmed the District Court’s March 25, 2020 order requiring an EIS and its July 6, 2020 order vacating the
easement. In this same January 26 order, the Court of Appeals also overturned the District Court’s July 6, 2020 order that the pipeline shut down and
be emptied of oil. Dakota Access filed for rehearing en banc on April 12, 2021, which the Court of Appeals denied. On September 20, 2021, Dakota
Access filed a petition with the U.S. Supreme Court to hear the case. Oppositions were filed by the Solicitor General (December 17, 2021) and the
Tribes (December 16, 2021). Dakota Access filed their reply on January 4, 2022. On February 22, 2022, the U.S. Supreme Court declined to hear the
case.
The District Court scheduled a status conference for February 10, 2021 to discuss the effects of the Court of Appeals’ January 26, 2021 order on the
pending motion for injunctive relief, as well as USACE’s expectations as to how it will proceed regarding its enforcement discretion regarding the
easement. On May 3, 2021, USACE advised the District Court that it had not changed its position with respect to its opposition to the Tribes’ motion
for injunction. On May 21, 2021, the District Court denied the plaintiffs’ request for an injunction. On June 22, 2021, the District Court terminated the
consolidated lawsuits and dismissed all remaining outstanding counts without prejudice.
On September 8, 2023, the USACE published the Draft EIS. Comments to the Draft EIS were due on December 13, 2023. The USACE anticipates that
a Final EIS and Record of Decision would be issued in 2024. The pipeline continues to operate pending completion of the EIS. Energy Transfer cannot
determine when or how future lawsuits will be resolved or the impact they may have on the Bakken Pipeline, which consists of both Dakota Access
and the Energy Transfer Crude Oil Pipeline; however, Energy Transfer expects that after the law and complete record are fully considered, any such
proceeding will be resolved in a manner that will allow the pipeline to continue to operate.
In addition, lawsuits and/or regulatory proceedings or actions of this or a similar nature could result in interruptions to construction or operations of
current or future projects, delays in completing those projects and/or increased project costs, all of which could have an adverse effect on our business
and results of operations.
Louisiana Dispute with New Generation Gas Gathering LLC
On August 31, 2023, Energy Partners, LP and ETC Texas Pipeline, LTD—corrected the next day to be ETC Texas Pipeline, Ltd, Gulf Run
Transmission LLC, Enable Midstream Partners LP and ETC Tiger Pipeline LLC (collectively “Energy Transfer”), filed a petition for declaratory
judgment against New Generation Gas Gathering LLC (“NG3”) in the 42nd Judicial District Court of DeSoto Parish, Louisiana. In relation to seven
specific servitudes in DeSoto Parish, Louisiana underlying Energy Transfer natural gas pipelines, Energy Transfer requested declarations from the
Court that pursuant to Louisiana Civil Code Article 720, NG3 must obtain Energy Transfer’s permission to install NG3’s proposed pipelines across the
Energy Transfer servitudes so that Energy Transfer may determine if NG3’s proposed installation of its proposed pipelines would interfere with Energy
Transfer’s use of its existing servitudes.
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On November 13, 2023, NG3 filed its answer and reconventional demand, a Louisiana term for counterclaim, asserting six causes of action against of
all the entities asserting the claim as well as Energy Transfer LP. In Count I, NG3 seeks declaratory judgment that Energy Transfer lacks the right to
object to its proposed crossings of Energy Transfer’s natural gas pipelines that adversely affect Energy Transfer. In Counts II–VI, NG3 asserts five
causes of action alleging that Energy Transfer’s objection and lawsuit seeking court determination that it has the right to object to NG3’s request to
cross Energy Transfer’s pipelines more than one hundred times constitutes tortious conduct, an abuse of Energy Transfer’s rights, an unfair trade
practice, and a violation of Louisiana Monopolies Act sections prohibiting conspiracies and monopolies/attempted monopolies.
On December 7, 2023, the trial court set the deadline for Energy Transfer to respond to NG3’s reconventional demand as February 9, 2024, set a
hearing on any exceptions for March 25, 2024, and tentatively set a trial date for September 9, 2024. The parties have begun written discovery. The
Court’s schedule is subject to dispute among the parties and has not yet been resolved by the Court.
On February 7, 2024, the Attorney General for the State of Louisiana, Public Protection Division (the “AG”) gave notice of a complaint filed by NG3.
NG3 asserts that Energy Transfer violated Louisiana Revised Statutes 51:1401, et seq., the Unfair Trade Practices and Consumer Protection Law. The
AG has not investigated this matter and it makes no determination as to the merits of same.
Energy Transfer cannot predict the ultimate outcome of this litigation but intends to vigorously defend themselves.
Mont Belvieu Incident
On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu LP’s (“Lone Star,” now
known as Energy Transfer Mont Belvieu NGLs LP) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface
release. The subsurface release caused a fire at Lone Star’s South Terminal and damage to Lone Star’s storage well operations at its South and North
Terminals. Normal operations resumed at the facilities in the fall of 2016, with the exception of one of Lone Star’s storage wells at the North Terminal
that has not been returned to service. Lone Star has obtained payment for most of the losses it has submitted to the adjacent operator. Lone Star
continues to quantify and seek reimbursement for outstanding losses.
MTBE Litigation
ETC Sunoco and Energy Transfer R&M (collectively, “Sunoco Defendants”) are defendants in lawsuits alleging MTBE contamination of groundwater.
The plaintiffs, state-level governmental entities, assert product liability, nuisance, trespass, negligence, violation of environmental laws and/or
deceptive business practices claims. The plaintiffs seek to recover compensatory damages, and in some cases also seek natural resource damages,
injunctive relief, punitive damages and attorneys’ fees.
As of December 31, 2023, Sunoco Defendants are defendants in two cases: one case initiated by the State of Maryland and one by the Commonwealth
of Pennsylvania. The actions brought also named as defendants ETO, ETP Holdco Corporation and Sunoco Partners Marketing & Terminals L.P., now
known as Energy Transfer Marketing & Terminals L.P. ETP Holdco Corporation and Energy Transfer Marketing & Terminals L.P. are wholly owned
subsidiaries of Energy Transfer.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in
excess of amounts accrued. An adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of
operations during the period in which any such adverse determination occurs, but such an adverse determination likely would not have a material
adverse effect on the Partnership’s consolidated financial position.
Litigation Filed By or Against Williams
In April and May 2016, The Williams Companies, Inc. (“Williams”) filed two lawsuits (the “Williams Litigation”) against Energy Transfer, LE GP,
LLC, and, in one of the lawsuits, Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC (collectively, “Energy Transfer
Defendants”) in the Delaware Court of Chancery (“the Court”), alleging that the Energy Transfer Defendants breached their obligations under the
Energy Transfer-Williams merger agreement (the “Merger Agreement”). In general, Williams alleges that the Energy Transfer Defendants breached the
Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax
opinion concerning Section 721 of the Internal Revenue Code (“721 Opinion”), (b) issuing the Partnership’s Series A convertible preferred units (the
“Issuance”) and (c) making allegedly untrue representations and
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warranties in the Merger Agreement. Williams asked the Court to compel the Energy Transfer Defendants to close the merger or take various other
affirmative actions.
After a two-day trial on June 20 and 21, 2016, the Court ruled in favor of the Energy Transfer Defendants and issued a declaratory judgment that
Energy Transfer could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court did not
reach a decision regarding Williams’ claims related to the Issuance or certain of the alleged untrue representations and warranties. On March 23, 2017,
the Delaware Supreme Court affirmed this ruling on the June 2016 trial. In September 2016, the parties filed amended pleadings. Williams filed an
amended complaint seeking a $410 million termination fee (the “Termination Fee”) based on the alleged breaches of the Merger Agreement listed
above. The Energy Transfer Defendants filed amended counterclaims and affirmative defenses, asserting that Williams materially breached the Merger
Agreement by, among other things, (a) modifying and qualifying its board recommendation in a manner adverse to the merger, (b) failing to use its
reasonable best efforts to consummate the merger, (c) failing to provide material information to Energy Transfer for inclusion in the Form S-4 related
to the merger, (d) failing to facilitate the financing of the merger and (e) breaching the Merger Agreement’s forum-selection clause. The Energy
Transfer Defendants sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct.
On September 29, 2016, Williams filed a motion to dismiss the Energy Transfer Defendants’ amended counterclaims and to strike certain of the
Energy Transfer Defendants’ affirmative defenses. On December 1, 2017, the Court issued a Memorandum Opinion granting in part and denying in
part Williams’ motion to dismiss. The Court dismissed, among other things, the Energy Transfer Defendants’ claim for a $1.48 billion termination fee.
Trial was held on all remaining claims on May 10-17, 2021, and on December 29, 2021, the Court ruled in favor of Williams and awarded it the
Termination Fee plus certain fees and expenses, holding that the Issuance breached the Merger Agreement and that Williams had not materially
breached the Merger Agreement, though the Court awarded sanctions against Williams due to its CEO’s intentional spoliation of evidence. The Court
subsequently awarded Williams approximately $190 million in attorneys’ fees, expenses and pre-judgment interest.
On September 21, 2022, the Court entered a final judgment against the Energy Transfer Defendants in the amount of approximately $601 million plus
post-judgment interest at a rate of 3.5% per year, compounded quarterly. The Energy Transfer Defendants filed a notice of appeal on October 21, 2022
and filed their opening brief in support of their appeal on December 30, 2022. Williams filed their answering brief on January 20, 2023, and the Energy
Transfer Defendants filed their reply brief on February 6, 2023. The Delaware Supreme Court heard oral argument on July 12, 2023.
On October 10, 2023, the Delaware Supreme Court affirmed. On October 25, 2023, Energy Transfer Defendants filed a motion for reargument. On
November 17, 2023, the Delaware Supreme Court denied the motion.
The mandate issued upon the disposition of that motion; at which time the previously-stayed judgment became effective, plus additional post-judgment
interest.
The Energy Transfer Defendants paid the judgment (in the amount of approximately $627 million) on November 28, 2023, concluding this matter.
Rover - State of Ohio
On November 3, 2017, the State of Ohio and the Ohio Environmental Protection Agency (“Ohio EPA”) filed suit against Rover and other defendants
(collectively, the “Defendants”) seeking to recover approximately $2.6 million in civil penalties allegedly owed and certain injunctive relief related to
permit compliance. The Defendants filed several motions to dismiss, which were granted on all counts. The Ohio EPA appealed, and on December 9,
2019, the Fifth District Court of Appeals entered a unanimous judgment affirming the trial court. The Ohio EPA sought review from the Ohio Supreme
Court. On April 22, 2020, the Ohio Supreme Court granted the review. On March 17, 2022, the Ohio Supreme Court reversed in part and remanded to
the Ohio trial court. The Ohio Supreme Court agreed with Rover that the State of Ohio had waived its rights under Section 401 of the Clean Water Act
but remanded to the trial court to determine whether any of the allegations fell outside the scope of the waiver.
On remand, the Ohio EPA voluntarily dismissed four of the other five defendants and dismissed one of its counts against Rover. In its Fourth Amended
Complaint, the Ohio EPA removed all paragraphs that alleged violations by the four dismissed defendants, including those where the dismissed
defendants were alleged to have acted jointly with Rover or others. At a June 2, 2022, status conference, the trial judge set a schedule for Rover and the
other remaining defendant to file motions to dismiss the Fourth Amended Complaint. On August 1, 2022, Rover and the other remaining defendant
each
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filed their respective motions. Briefing on those motions was completed on November 4, 2022. By order issued on October 20, 2023, the trial judge
dismissed the Ohio EPA’s Fourth Amended Complaint.
On November 17, 2023, the State of Ohio appealed the trial judge’s decision to Ohio’s Fifth District Court of Appeals. The State filed its initial brief
on January 8, 2024 and Energy Transfer’s and Rover’s responsive brief is currently due February 20, 2024. Energy Transfer and Rover intend to
vigorously defend this claim.
Unitholder Litigation Regarding Pipeline Construction
Various purported unitholders of Energy Transfer have filed derivative actions against various past and current members of Energy Transfer’s Board of
Directors, LE GP, LLC, and Energy Transfer, as a nominal defendant that assert claims for breach of fiduciary duties, unjust enrichment, waste of
corporate assets, breach of Energy Transfer’s Partnership Agreement, tortious interference, abuse of control and gross mismanagement related
primarily to matters involving the construction of pipelines in Pennsylvania and Ohio. They also seek damages and changes to Energy Transfer’s
corporate governance structure. See Bettiol v. LE GP, Case No. 3:19-cv-02890-X (N.D. Tex.); Davidson v. Kelcy L. Warren, Cause No. DC-20-02322
(44th Judicial District of Dallas County, Texas); Harris v. Kelcy L. Warren, Case No. 2:20-cv-00364-GAM (E.D. Pa.); Barry King v. LE GP, Case No.
3:20-cv-00719-X (N.D. Tex.); Inter-Marketing Group USA, Inc. v. LE GP, et al., Case No. 2022-0139-SG (Del. Ch.); Elliot v. LE GP LLC, Case No.
3:22-cv-01527-B (N.D. Tex.); Chapa v. Kelcy L. Warren, et al., Index No. 611307/2022 (N.Y. Sup. Ct.); Elliott v. LE GP et al, Cause No. DC-22-
14194 (Dallas County, Tex.); and Charles King v. LE GP, LLC et al, Cause No. DC-22-14159 (Dallas County, Texas). The Barry King action that was
filed in the United States District Court for the Northern District of Texas (Case No. 3:20-cv-00719-X) has been consolidated with the Bettiol action.
On August 9, 2022, the Elliot action that was filed in the United States District Court for the Northern District of Texas (Case No. 3:22-cv-01527-B)
was voluntarily dismissed.
Another purported unitholder of Energy Transfer, Allegheny County Employees’ Retirement System (“ACERS”), individually and on behalf of all
others similarly situated, filed a suit under the federal securities laws purportedly on behalf of a class, against Energy Transfer and three of Energy
Transfer’s directors: Kelcy L. Warren, John W. McReynolds and Thomas E. Long. See Allegheny County Emps.’ Ret. Sys. v. Energy Transfer LP,
Case No. 2:20-00200-GAM (E.D. Pa.). On June 15, 2020, ACERS filed an amended complaint and added as additional defendants Energy Transfer
directors Marshall S. McCrea and Matthew S. Ramsey, as well as Michael J. Hennigan and Joseph McGinn. The amended complaint asserts claims for
violations of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder related primarily to matters involving the
construction of pipelines in Pennsylvania. On August 14, 2020, the defendants filed a motion to dismiss ACERS’ amended complaint. On April 6,
2021, the court granted in part and denied in part the defendants’ motion to dismiss. The court held that ACERS could proceed with its claims
regarding certain statements put at issue by the amended complaint while also dismissing claims based on other statements. The court also dismissed
without prejudice the claims against defendants McReynolds, McGinn and Hennigan. Discovery is ongoing. On August 23, 2022, the court granted in
part and denied in part ACERS’ motion for class certification. The court certified a class consisting of those who purchased or otherwise acquired
common units of Energy Transfer between February 25, 2017 and November 11, 2019.
On June 3, 2022, another purported unitholder of Energy Transfer, Mike Vega, filed suit, purportedly on behalf of a class, against Energy Transfer and
Messrs. Warren, Long, McCrea and Whitehurst. See Vega v. Energy Transfer LP et al., Case No. 1:22-cv-4614 (S.D.N.Y.). The action asserts claims
for violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder related primarily to
statements made in connection with the construction of Rover. On August 10, 2022, the court appointed the New Mexico State Investment Council and
Public Employees Retirement Association of New Mexico (the “New Mexico Funds”) as lead plaintiffs. New Mexico Funds filed an amended
complaint on September 30, 2022 and added as additional defendants Energy Transfer directors John W. McReynolds and Matthew S. Ramsey. On
November 7, 2022, the court granted the defendants’ motion to transfer and transferred this action to the United States District Court for the Northern
District of Texas. On January 27, 2023, the defendants filed their motion to dismiss the New Mexico Funds’ amended complaint.
The defendants cannot predict the outcome of these lawsuits or any lawsuits that might be filed subsequent to the date of this filing, nor can the
defendants predict the amount of time and expense that will be required to resolve these lawsuits. However, the defendants believe that the claims are
without merit and intend to vigorously contest them.
Cline Class Action
On July 7, 2017, Perry Cline filed a class action complaint in the Eastern District of Oklahoma against Sunoco, Inc. (R&M), LLC (now known as
Energy Transfer R&M) and Energy Transfer Marketing & Terminals L.P. (collectively, “ETMT”) that alleged ETMT failed to make timely payments
of oil and gas proceeds from Oklahoma wells and to pay statutory interest for those untimely payments. On October 3, 2019, the District Court
certified a class to include all persons
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who received untimely payments from Oklahoma wells on or after July 7, 2012, and who have not already been paid statutory interest on the untimely
payments (the “Class”). Excluded from the Class are those entitled to payments of proceeds that qualify as “minimum pay,” prior period adjustments
and pass through payments, as well as governmental agencies and publicly traded oil and gas companies.
After a bench trial, on August 17, 2020, Judge John Gibney (sitting from the Eastern District of Virginia) issued an opinion that awarded the Class
actual damages of $74.8 million for late payment interest for identified and unidentified royalty owners and interest-on-interest. This amount was later
amended to $80.7 million to account for interest accrued from trial (the “Order”). Judge Gibney also awarded punitive damages in the amount of
$75 million. The Class is also seeking attorneys’ fees.
On August 27, 2020, ETMT filed its Notice of Appeal with the 10th Circuit Court of Appeals (“10th Circuit”) and appealed the entirety of the Order.
The matter was fully briefed, and oral argument was set for November 15, 2021. However, on November 1, 2021, the 10th Circuit dismissed the appeal
due to jurisdictional concerns with finality of the Order. En banc rehearing of this decision was denied on November 29, 2021. On December 1, 2021,
ETMT filed a Petition for Writ of Mandamus to the 10th Circuit to correct the jurisdictional problems and secure final judgment. On February 2, 2022,
the 10th Circuit denied the Petition for Writ of Mandamus, citing that there are other avenues for ETMT to obtain adequate relief. On February 10,
2022, ETMT filed a Motion to Modify the Plan of Allocation Order and Issue a Rule 58 Judgment with the trial court, requesting the District Court to
enter a final judgment in compliance with the Rules. ETMT also filed an injunction with the trial court to enjoin all efforts by plaintiffs to execute on
any non-final judgment. On March 31, 2022, Judge Gibney denied the Motion to Modify the Plan of Allocation, reiterating his thoughts that the order
constitutes a final judgment. Judge Gibney granted the injunction in part (placing a hold on enforcement efforts for 60 days) and denied the injunction
in part. The injunction has since been lifted.
Despite the fact that ETMT has taken the position that the judgment is not final and not subject to execution, the Class engaged in asset discovery and
actively tried to collect on the judgment through garnishment proceedings from ETMT’s customers. ETMT unsuccessfully tried to deposit the funds
into the District Court’s Registry. Accordingly, to stop the garnishment proceedings, on December 2, 2022, ETMT wired approximately $161 million
to the Plaintiff’s approved Plan Administrator, which represented at the time the full amount of the judgment with attorney’s fees and post-judgment
interest. ETMT did so without waiving its ability to pursue its pending appeal or its right to appeal the merits of the judgment. Plaintiff has since
dismissed the garnishment actions.
ETMT cannot predict the outcome of the case, nor can ETMT predict the amount of time and expense that will be required to resolve the appeal.
ETMT has been vigorous and diligent in its appeals relating to the finality issues underlying the Order and appealed the denial of the Motion to Modify
to the 10th Circuit in an attempt to get a decision on finality. The appeal was fully briefed, and oral argument was held on March 21, 2023. On August
3, 2023, the 10th Circuit ruled in favor of ETMT and found that the district court’s plan of allocation (which was part of the final judgment) did not
satisfy all finality requirements. The Court held that the district court abused its discretion in denying ETMT’s Rule 60(b)(6) Motion to Modify and
reversed and remanded for further proceedings. The case was sent back to the trial court so that the district court could fix the finality requirements
with the judgment. Further, ETMT sought and recovered a return of funds deposited with the Plan Administrator; Class Counsel did not oppose this
motion.
At a status hearing on September 28, 2023, Class Counsel indicated that it would seek additional interest up until the date that the final judgment is
entered. The District Court asked for briefing on the issue of additional interest and held a hearing on October 17, 2023 to address this issue further and
enter a ruling as to whether additional interest should be added to the judgment total. During the hearing, the District Court ruled that additional
interest should be awarded at the 12% statutory rate from the date of the prior improper judgment up until October 17, 2023. However, the Judge tolled
the running of interest for the time period during which the Plan Administrator was in possession of ETMT’s funds (between November 2, 2022 and
October 10, 2023). Based on this ruling, the Class calculated that approximately $23 million in additional interest should be added to the final
judgment. On October 19, 2023, the District Court entered the new final judgment with a corrected Plan of Allocation. Both parties agree that this
newly entered judgment fixes the finality concerns and will allow an appeal to the 10th Circuit on the merits. With the inclusion of additional interest,
the total amount awarded to the Plaintiffs is approximately $104 million in actual damages and $75 million in punitive damages. ETMT intends on
appealing the entirety of the judgment and filed its Notice of Appeal to the Tenth Circuit on December 15, 2023.
Energy Transfer LP and ETC Texas Pipeline, Ltd. v. Culberson Midstream LLC, et al.
On April 8, 2022, Energy Transfer and ETC Texas Pipeline, Ltd. (“ETC,” and together with Energy Transfer, “Plaintiffs”) filed suit against Culberson
Midstream LLC (“Culberson”), Culberson Midstream Equity, LLC (“Culberson Equity”), and Moontower Resources Gathering, LLC (“Moontower”).
On October 1, 2018, ETC and Culberson entered into a Gas
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Gathering and Processing Agreement (the “Bypass GGPA”) under which Culberson was to gather gas from its dedicated acreage and deliver all
committed gas exclusively to ETC. In connection with the Bypass GGPA, on October 18, 2018, Energy Transfer and Culberson Equity also entered
into an Option Agreement. Under the Option Agreement, Culberson Equity and Moontower had the right (but not the obligation) to require Energy
Transfer to purchase their respective interests in Culberson by way of a put option. Notably, the Option Agreement is only enforceable so long as the
parties comply with the Bypass GGPA. In late March 2022, Culberson Equity and Moontower submitted a put notice to Energy Transfer seeking to
require Energy Transfer to purchase their respective interests in Culberson for approximately $93 million. On April 8, 2022, Plaintiffs filed suit against
Culberson, Culberson Equity and Moontower asserting claims for declaratory judgment and breach of contract, contending that they materially
breached the Bypass GGPA by sending some committed gas to third parties and also by failing to send any gas to Plaintiffs since March 2020, and thus
that Culberson Equity’s and Moontower’s put notice is void. Culberson, Culberson Equity, and Moontower have answered the lawsuit. Additionally,
Culberson filed a counterclaim against ETC for breach of the Bypass GGPA, seeking the recovery of damages and attorneys’ fees. Culberson Equity
and Moontower also filed a counterclaim against Energy Transfer for (1) breach of the Option Agreement, and (2) a declaratory judgment concerning
Energy Transfer’s alleged obligation to purchase the Culberson interests. The lawsuit is pending in the 193rd Judicial District Court (“the Court”) in
Dallas County, Texas. On April 27, 2022, Culberson filed an application for a temporary restraining order, temporary injunction, and permanent
injunction, and Culberson Equity and Moontower joined in that request. The Court held a hearing on the application on April 28 and denied the
injunction. In early May, Culberson filed a motion to enforce the appraisal process and confirm the validity of their put price calculation, to which
Plaintiffs objected. On July 11, 2022, the Court held a hearing on the motion, and on July 19, 2022, the Court ordered the parties to engage in an
appraisal process regarding the put price. An independent appraiser was appointed and issued his decision on October 15, 2022, concluding that the put
price totals $93 million. Plaintiffs have consistently reiterated their objection to the appraisal process and conclusion.
On October 6, 2022, Culberson, Culberson Equity and Moontower filed a motion for summary judgment, but the Court postponed considering it until
after further document discovery and depositions. On December 7, 2022, Plaintiffs amended their petition to add Moontower Resources Operating,
LLC and Moontower Resources WI, LLC as Defendants, and to assert a claim against all Defendants for fraudulent inducement.
Defendants refiled updated motions for summary judgment on May 5, 2023, seeking summary judgment on: (1) Plaintiffs’ breach of contract and
declaratory judgment claims on a no-evidence basis; (2) Plaintiffs’ fraud and alter ego claims on a no-evidence basis; and (3) Plaintiffs’ fraud claim on
a traditional basis. Plaintiffs responded on June 6, 2023. Defendants submitted their replies in support of summary judgment on June 12, 2023.
On June 5, 2023, counsel for Defendants informed the Court via a letter that Defendants were continuing the submission date of the no-evidence
motion regarding Plaintiffs’ breach of contract and declaratory judgment claims, noting that such submission would be rescheduled along with a
traditional summary judgment motion regarding the same subject matter. To that end, on July 17, 2023, Defendant Culberson Midstream, LLC filed a
Traditional Motion for Summary Judgment on Plaintiffs’ Breach of Contract and Declaratory Judgment Claims, while Defendants Culberson
Midstream Equity, LLC and Moontower Resources Gathering filed a Motion for Partial Summary Judgment Regarding the Breach of the Option
Agreement. Further, on July 25, 2023, Defendants filed a Traditional and No-Evidence Motion for Summary Judgment Regarding Damages and
Recission. On July 28, 2023, in turn, Plaintiff ETC Texas Pipeline, Ltd. filed a Traditional Motion for Partial Summary Judgment on Breach of
Contract and Declaratory Judgment.
On September 20, 2023, the Court held oral argument on the various Motions for Summary Judgment. Following oral argument, on September 26,
2023, the Court ruled on each of the Motions. The Court denied Defendants’ Traditional Motion for Partial Summary Judgment Regarding Fraud,
Defendants’ No Evidence Motion for Summary Judgment Regarding Plaintiffs’ Fraud and Alter Ego Claims, Defendants’ Traditional and No Evidence
Motion for Partial Summary Judgment Regarding Damages and Rescission, and Plaintiff ETC Texas Pipeline, Ltd.’s Traditional Motion for Partial
Summary Judgment on Breach of Contract and Declaratory Judgment. The Court granted Culberson Midstream, LLC’s Traditional Motion for Partial
Summary Judgment Seeking Dismissal of Plaintiffs’ Breach of Contract and Declaratory Judgment Claims and Culberson Midstream Equity, LLC and
Moontower Resources Gathering, LLC’s Motion for Partial Summary Judgment Regarding Breach of the Option Agreement. Defendants have filed a
motion seeking permission from the appellate court to allow an interlocutory appeal of the order denying their Traditional Motion for Partial Summary
Judgment Regarding Fraud. That motion remains pending before the appellate court.
Discovery has closed in this matter. Trial on Plaintiff Energy Transfer LP’s fraud claim is currently set for June 18, 2024. Plaintiffs cannot predict the
ultimate outcome of this litigation or the amount of time and expense that will be required to resolve it.
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Massachusetts Attorney General v. New England Gas Company
On July 7, 2011, the Massachusetts Attorney General (the “MA AG”) filed a regulatory complaint with the Massachusetts Department of Public
Utilities (“DPU”) against New England Gas Company (“NEG”) with respect to certain environmental cost recoveries. NEG was an operating division
of Southern Union Company (“SUG”), and the NEG assets were acquired in connection with the merger transaction with Energy Transfer in March
2012. Subsequent to the merger, in 2013, SUG sold the NEG assets to Liberty Utilities (“Liberty,” and together with NEG and SUG, “Respondents”)
and retained certain potential liabilities, including the environmental cost recoveries with respect to the pending complaint before the DPU.
Specifically, the MA AG seeks a refund to NEG’s ratepayers for approximately $18 million in legal fees associated with SUG environmental response
activities. The MA AG requests that the DPU initiate an investigation into NEG’s collection and reconciliation of recoverable environmental costs,
namely: (1) the legal fees charged by the Kasowitz, Benson, Torres & Friedman firm and passed through the recovery mechanism since 2005; (2) the
legal fees charged by the Bishop, London & Dodds firm and passed through the recovery mechanisms since 2005; and (3) the legal fees passed through
the recovery mechanism that the MA AG contends only qualify for a lesser (i.e., 50%) level of recovery. Respondents maintain that, by tariff, these
costs are recoverable through rates charged to NEG customers pursuant to the environmental remediation adjustment clause program. After the
Respondents answered the complaint and filed a motion to dismiss in 2011, the Hearing Officer deferred decision on the motion to dismiss and issued
a stay of discovery pending resolution of a discovery dispute, which it later lifted on June 24, 2013, permitting the case to resume. However, the MA
AG failed to take any further steps to prosecute its claims for nearly seven years. The case remained largely dormant until February 2022, when the
Hearing Officer denied the motion to dismiss. After receiving input from the parties, the Hearing Officer entered a procedural schedule on March 16,
2022 (which was amended slightly on August 22, 2022). The parties engaged in discovery and the preparation of pre-filed testimony. Respondents
submitted their pre-filed testimony on July 11, 2022. The MA AG served three sets of discovery requests on Respondents on September 9, September
12, and September 20, respectively, to which Respondents timely responded. On October 5, 2022, the MA AG requested that the DPU issue a ruling on
whether the information that Respondents redacted in their attorneys’ fees invoices is protected by the attorney-client privilege. On the same day, the
MA AG also filed a Motion to Stay the Procedural Schedule pending a ruling on the privilege issue. On October 6, 2022, without even affording
Respondents the opportunity to respond, the DPU granted the MA AG’s request to stay the procedural schedule. Accordingly, all previous deadlines
(including the MA AG’s October 7, 2022, deadline to submit direct pre-filed testimony) are presently stayed. On October 18, 2023, the DPU issued an
Order on Attorney General’s Motion to Compel, ruling on issues originally raised in a motion to compel that the MA AG filed in 2013. The October
18, 2023 Order directs NEG to review its redactions again and, to the extent any invoices are completely redacted or heavily redacted, to provide more
lightly redacted versions within 30 days. The October 18, 2023 Order also states that the MDPU will set a new procedural schedule in this matter
sometime after NEG complies with the directives in the order, which the Company has completed as of January 17, 2024.
Crestwood Midstream Partners, LP – Linde Litigation
On December 23, 2019, Linde Engineering North America Inc. (“Linde”) filed a lawsuit in the District Court of Harris County, Texas alleging that
Arrow Field Services, LLC, our consolidated subsidiary, and Crestwood Midstream Partners, LP (collectively, “Crestwood”) breached a contract
entered into in March 2018 under which Linde was to provide engineering, procurement and construction services to Crestwood related to the
completion of the construction of the Bear Den II cryogenic processing plant.
Trial was held in June 2022, and a final judgment was entered on October 24, 2022. The final judgment includes an award of damages of
approximately $20.7 million, a pre-judgment interest award of approximately $17.7 million and attorney fees and other costs of approximately
$4.7 million. Crestwood has insurance coverage related to certain pre-judgment interest awards but has not recorded a receivable related to any
potential insurance recovery on June 30, 2023. On January 9, 2023, Crestwood paid approximately $21.2 million to the Court Registry under protest to
mitigate the impact of post-judgment interest. Crestwood filed a Notice of Appeal on January 13, 2023, and filed its Appellate Brief on September 29,
2023. Linde’s response was filed on February 8, 2024. Crestwood anticipates that oral argument will be held in late 2024. Crestwood is unable to
predict the ultimate outcome on the appeal related to this matter.
Environmental Matters
Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure
compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as
well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but
there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal
requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and
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operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to
comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory,
remedial and corrective action obligations, natural resource damages, the issuance of injunctions in affected areas and the filing of federally authorized
citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we
may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected
outcome.
Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination,
the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the
extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on our
results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position.
Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental
matters is adequate to cover the potential exposure for cleanup costs.
Environmental Remediation
Our subsidiaries are responsible for environmental remediation at certain sites, including the following:
•
•
•
•
Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments
are ongoing and, in some cases, our subsidiaries could be contractually responsible for contamination caused by other parties.
Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets,
retail sites that the Partnership no longer operates, closed and/or sold refineries and other formerly owned sites.
The Partnership is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a
potentially responsible party (“PRP”). As of December 31, 2023, the Partnership had been named as a PRP at approximately 32 identified or
potentially identifiable “Superfund” sites under federal and/or comparable state law. The Partnership is usually one of a number of companies
identified as a PRP at a site. The Partnership has reviewed the nature and extent of its involvement at each site and other relevant circumstances
and, based upon the Partnership’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant.
To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets.
In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and
former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies,
amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets.
The following table reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are
considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of
amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would
require disclosure in our consolidated financial statements.
Current
Non-current
Total environmental liabilities
December 31,
2023
2022
$
$
42 $
235
277 $
54
228
282
We have established a wholly owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites
that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred
but not reported, based on an actuarially determined
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fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are
used to develop the premiums paid to the captive insurance company.
During the years ended December 31, 2023 and 2022, the Partnership recorded $29 million and $30 million, respectively, of expenditures related to
environmental cleanup programs.
Our pipeline operations are subject to regulation by the DOT under PHMSA, pursuant to which PHMSA has established requirements relating to the
design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, PHMSA, through the Office of
Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their
pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these
integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the
integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and
analysis. Integrity testing and assessment of all of these assets will continue, and the results of such testing and assessment could cause us to incur
future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines;
however, no estimate can be made at this time of the likely range of such expenditures.
Our operations are also subject to the requirements of OSHA, and comparable state laws that regulate the protection of the health and safety of
employees. In addition, the Occupational Safety and Health Administration’s hazardous communication standard requires that information be
maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local
government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping
requirements and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations;
however, there is no assurance that such costs will not be material in the future.
12. REVENUE:
Disaggregation of revenue
The major types of revenue within our reportable segments are as follows:
•
•
intrastate transportation and storage;
interstate transportation and storage;
• midstream;
• NGL and refined products transportation and services;
•
•
crude oil transportation and services;
investment in Sunoco LP;
•
•
fuel distribution and marketing;
all other;
•
investment in USAC;
•
•
contract operations;
retail parts and services; and
•
all other.
Note 16 depicts the disaggregation of revenue by segment, with revenue amounts reflected in accordance with ASC Topic 606.
Intrastate transportation and storage revenue
Our intrastate transportation and storage segment’s revenues are determined primarily by the volume of capacity our customers reserve as well as the
actual volume of natural gas that flows through the transportation pipelines or that is injected or withdrawn into or out of our storage facilities. Firm
transportation and storage contracts require customers to pay certain minimum fixed fees regardless of the volume of commodity they transport or
store. These contracts typically include a variable incremental charge based on the actual volume of transportation commodity throughput or stored
commodity injected/withdrawn. Under interruptible transportation and storage contracts, customers are not required to pay
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any fixed minimum amounts, but are instead billed based on actual volume of commodity they transport across our pipelines or inject/withdraw into or
out of our storage facilities. Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life
of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not
separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The
fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over
time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual
volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a
case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts
at the time the services are performed.
Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent
power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural
gas from the market, including purchases from our marketing operations, and from producers at the wellhead.
Interstate transportation and storage revenue
Our interstate transportation and storage segment’s revenues are determined primarily by the amount of capacity our customers reserve as well as the
actual volume of natural gas that flows through the transportation pipelines or that is injected into or withdrawn out of our storage facilities. Our
interstate transportation and storage segment’s contracts can be firm or interruptible. Firm transportation and storage contracts require customers to pay
certain minimum fixed fees regardless of the volume of commodity transported or stored. In exchange for such fees, we must stand ready to perform a
contractually agreed-upon minimum volume of services whenever the customer requests such services. These contracts typically include a variable
incremental charge based on the actual volume of transportation commodity throughput or stored commodity injected or withdrawn. Under
interruptible transportation and storage contracts, customers are not required to pay any fixed minimum amounts, but are instead billed based on actual
volume of commodity they transport across our pipelines or inject into or withdraw out of our storage facilities. Consequently, we are not required to
stand ready to provide any contractually agreed-upon volume of service, but instead provides the services based on existing capacity at the time the
customer requests the services. Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or storage) daily over the life
of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not
separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The
fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over
time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual
volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a
case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts
at the time the services are performed.
Lake Charles LNG’s revenues are primarily derived from terminalling services for shippers by receiving LNG at the facility for storage and delivering
such LNG to shippers, either in liquid state or gaseous state after regasification. Lake Charles LNG derives all of its revenue from a series of long-term
contracts with a wholly owned subsidiary of Royal Dutch Shell plc (“Shell”). Terminalling revenue is generated from fees paid by Shell for storage
and other associated services at the terminal. Payment for services under these contracts are typically due the month after the services have been
performed.
The terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged regardless of the
volumes transported by Shell or services provided at the terminal.
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The performance obligation with respect to firm contracts is a promise to provide a single type of service (terminalling) daily over the life of the
contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are not
separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The
fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over
time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual
volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
Midstream revenue
Our midstream segment’s revenues are derived primarily from margins we earn for natural gas volumes that are gathered, processed and/or
transported. The various types of revenue contracts our midstream segment enters into include:
Fixed fee gathering and processing: Contracts under which we provide gathering and processing services in exchange for a fixed cash fee per unit of
volume. Revenue for cash fees is recognized when the service is performed.
Keepwhole: Contracts under which we gather raw natural gas from a third-party producer, process the gas to convert it to pipeline quality natural gas,
and redeliver to the producer a thermal-equivalent volume of pipeline quality natural gas. In exchange for these services, we retain the NGLs extracted
from the raw natural gas received from the producer as well as cash fees paid by the producer. The value of NGLs retained as well as cash fees is
recognized as revenue when the services are performed.
Percent of Proceeds (“POP”): Contracts under which we provide gathering and processing services in exchange for a specified percentage of the
producer’s commodity (“POP percentage”) and also in some cases additional cash fees. The two types of POP revenue contracts are described below:
•
In-Kind POP: We retain our POP percentage (non-cash consideration) and also any additional cash fees in exchange for providing the services.
We recognize revenue for the non-cash consideration and cash fees at the time the services are performed.
• Mixed POP: We purchase NGLs from the producer and retain a portion of the residue gas as non-cash consideration for services provided. We
may also receive cash fees for such services. Under Topic 606, these agreements were determined to be hybrid agreements which were partially
supply agreements (for the NGLs we purchased) and customer agreements (for the services provided related to the product that was returned to the
customer). Given that these are hybrid agreements, we split the cash and non-cash consideration between revenue and a reduction of costs based
on the value of the service provided vs. the value of the supply received.
Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligations with respect to our midstream segment’s contracts are to provide gathering, transportation and processing services, each
of which would be completed on or about the same time, and each of which would be recognized on the same line item on the income statement,
therefore identification of separate performance obligations would not impact the timing or geography of revenue recognition.
Certain contracts of our midstream segment include throughput commitments under which customers commit to purchasing a certain minimum volume
of service over a specified time period. If such volume of service is not purchased by the customer, deficiency fees are billed to the customer. In some
cases, the customer is allowed to apply any deficiency fees paid to future purchases of services. In such cases, we defer revenue recognition until the
customer uses the deficiency fees for services provided or becomes unable to use the fees as payment for future services due to expiration of the
contractual period the fees can be applied or physical inability of the customer to utilize the fees due to capacity constraints.
Our midstream segment also generates revenues from the sale of residue gas and NGLs at the tailgate of our processing facilities primarily to affiliates
and some third-party customers.
NGL and refined products transportation and services revenue
Our NGL and refined products transportation and services segment’s revenues are primarily derived from transportation, fractionation, blending and
storage of NGL and refined products as well as acquisition and marketing activities. Revenues are generated utilizing a complementary network of
pipelines, storage and blending facilities, and strategic offtake locations that provide access to multiple NGL markets. Transportation, fractionation and
storage revenue is generated from
F - 57
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Index to Financial Statements
fees charged to customers under a combination of firm and interruptible contracts. Firm contracts are in the form of take-or-pay arrangements where
certain fees will be charged to customers regardless of the volume of service they request for any given period. Under interruptible contracts,
customers are not required to pay any fixed minimum amounts, but are instead billed based on actual volume of service provided for any given period.
Payment for services under these contracts are typically due the month after the services have been performed.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation, fractionation, blending, or
storage) daily over the life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be
performed, these activities are not separable because such activities in combination are required to successfully transfer the overall service for which
the customer has contracted. The fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed
consideration is recognized over time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service.
Incremental fees associated with actual volume for each respective period are recognized as revenue in the period the incremental volume of service is
performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of services, but such promise is made on a
case-by-case basis at the time the customer requests the service and we accept the customer’s request. Revenue is recognized for interruptible contracts
at the time the services are performed.
Crude oil transportation and services revenue
Our crude oil transportation and services segment’s revenues are primarily derived from providing transportation, terminalling and acquisition and
marketing services to crude oil markets throughout the Southwest, Midwest and Northeast United States. Crude oil transportation revenue is generated
from tariffs paid by shippers utilizing our transportation services and is generally recognized as the related transportation services are provided. Crude
oil terminalling revenue is generated from fees paid by customers for storage and other associated services at the terminal. Crude oil acquisition and
marketing revenue is generated from sale of crude oil acquired from a variety of suppliers to third parties. Payment for services under these contracts
are typically due the month after the services have been performed.
Certain transportation and terminalling agreements are considered to be firm agreements, because they include fixed fee components that are charged
regardless of the volume of crude oil transported by the customer or services provided at the terminal. For these agreements, any fixed fees billed in
excess of services provided are not recognized as revenue until the earlier of (i) the time at which the customer applies the fees against cost of service
provided in a later period, or (ii) the customer becomes unable to apply the fees against cost of future service due to capacity constraints or contractual
terms.
The performance obligation with respect to firm contracts is a promise to provide a single type of service (transportation or terminalling) daily over the
life of the contract, which is fundamentally a “stand-ready” service. While there can be multiple activities required to be performed, these activities are
not separable because such activities in combination are required to successfully transfer the overall service for which the customer has contracted. The
fixed consideration of the transaction price is allocated ratably over the life of the contract and revenue for the fixed consideration is recognized over
time, because the customer simultaneously receives and consumes the benefit of this “stand-ready” service. Incremental fees associated with actual
volume for each respective period are recognized as revenue in the period the incremental volume of service is performed.
The performance obligation with respect to interruptible contracts is also a promise to provide a single type of service, but such promise is made on a
case-by-case basis at the time the customer requests the service and/or product and we accept the customer’s request. Revenue is recognized for
interruptible contracts at the time the services are performed.
Sunoco LP’s fuel distribution and marketing revenue
Sunoco LP’s fuel distribution and marketing operations earn revenue from the following channels: sales to dealers, sales to distributors, unbranded
wholesale revenue, commission agent revenue, rental income and other income. Motor fuel revenue consists primarily of the sale of motor fuel under
supply agreements with third party customers and affiliates. Fuel supply contracts with Sunoco LP’s customers generally provide that Sunoco LP
distribute motor fuel at a formula price based on published rates, volume-based profit margin and other terms specific to the agreement. The customer
is invoiced the agreed-upon price with most payment terms ranging less than 30 days. If the consideration promised in a contract includes a variable
amount, Sunoco LP estimates the variable consideration amount and factors in such an estimate to determine the transaction price under the expected
value method.
Revenue is recognized under the motor fuel contracts at the point in time the customer takes control of the fuel. At the time control is transferred to the
customer the sale is considered final, because the agreements do not grant customers the right
F - 58
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Index to Financial Statements
to return motor fuel. To determine when control transfers to the customer, the shipping terms of the contract are assessed as a primary indicator of the
transfer of control. For FOB shipping point terms, revenue is recognized at the time of shipment. The performance obligation with respect to the sale of
goods is satisfied at the time of shipment since the customer gains control at this time under the terms. Shipping and/or handling costs that occur before
the customer obtains control of the goods are deemed to be fulfillment activities and are accounted for as fulfillment costs. Once the goods are shipped,
Sunoco LP is precluded from redirecting the shipment to another customer and revenue is recognized.
Commission agent revenue consists of sales from commission agent agreements between Sunoco LP and select operators. Sunoco LP supplies motor
fuel to sites operated by commission agents and sells the fuel directly to the end customer. In commission agent arrangements, control of the product is
transferred at the point in time when the goods are sold to the end customer. To reflect the transfer of control, Sunoco LP recognizes commission agent
revenue at the point in time fuel is sold to the end customer.
Sunoco LP receives rental income from leased or subleased properties. Revenue from leasing arrangements for which Sunoco LP is the lessor is
recognized ratably over the term of the underlying lease.
Sunoco LP’s all other revenue
Sunoco LP’s all other operations earn revenue from the following channels: motor fuel sales, rental income and other income. Motor fuel sales consist
of fuel sales to consumers at company-operated retail stores. Other income includes merchandise revenue that comprises the in-store merchandise and
food service sales at company-operated retail stores, and other revenue that represents a variety of other services within Sunoco LP’s all other
operations including credit card processing, car washes, lottery, automated teller machines, money orders, prepaid phone cards and wireless services.
Revenue from all other operations is recognized when (or as) the performance obligations are satisfied (i.e. when the customer obtains control of the
good or the service is provided).
USAC’s contract operations revenue
USAC’s revenue from contracted compression, natural gas treating and maintenance services is recognized ratably under its fixed-fee contracts over
the term of the contract as services are provided to its customers. Initial contract terms typically range from six months to five years; however, USAC
usually continues to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-
to-month or longer basis. USAC primarily enters into fixed-fee contracts whereby its customers are required to pay the monthly fee even during
periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month,
except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of the invoice.
Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of
consideration USAC receives and revenue it recognizes is based upon the fixed fee rate stated in each service contract.
Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.
USAC’s contracts with customers may include multiple performance obligations. For such arrangements, USAC allocates revenues to each
performance obligation based on its relative standalone service fee. USAC generally determines standalone service fees based on the service fees
charged to customers or using expected cost plus margin.
The majority of USAC’s service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly
basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same
service month to month and is promised consecutively over the service contract term. USAC measures progress and performance of the service
consistently using a straight-line, time-based method as each month passes, because its performance obligations are satisfied evenly over the contract
term as the customer simultaneously receives and consumes the benefits provided by its service. If variable consideration exists, it is allocated to the
distinct monthly service within the series to which such variable consideration relates. USAC has elected to apply the invoicing practical expedient to
recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on its performance
completed to date.
There are typically no material obligations for returns or refunds. USAC’s standard contracts do not usually include material non-cash consideration.
F - 59
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Index to Financial Statements
USAC’s retail parts and services revenue
USAC’s retail parts and services revenue is primarily earned on directly reimbursable freight and crane charges that are the financial responsibility of
USAC’s customers and maintenance work on units at its customers’ locations that are outside the scope of its core maintenance activities. Revenue
from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer.
At such time, the customer has the ability to direct the use of the benefits of such part or service after USAC has performed its services. USAC bills
upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of the invoice. The amount of consideration
USAC receives and revenue it recognizes is based on the invoice amount. There are typically no material obligations for returns, refunds, or
warranties. USAC’s standard contracts do not usually include material variable or non-cash consideration.
All other revenue
Our all other segment primarily includes our compression equipment business which provides full-service compression design and manufacturing
services for the oil and gas industry. It also includes the management of coal and natural resources properties and the related collection of royalties. We
also earn revenues from other land management activities, such as selling standing timber, leasing coal-related infrastructure facilities and collecting
oil and gas royalties. These operations also include end-user coal handling facilities.
Contract Balances with Customers
The Partnership satisfies its obligations by transferring goods or services in exchange for consideration from customers. The timing of performance
may differ from the timing the associated consideration is paid to or received from the customer, thus resulting in the recognition of a contract asset or
a contract liability.
The Partnership recognizes a contract asset when making upfront consideration payments to certain customers or when providing services to customers
prior to the time at which the Partnership is contractually allowed to bill for such services.
The Partnership recognizes a contract liability if the customer’s payment of consideration precedes the Partnership’s fulfillment of the performance
obligations. Certain contracts contain provisions requiring customers to pay a fixed minimum fee, but allows customers to apply such fees against
services to be provided at a future point in time. These amounts are reflected as deferred revenue until the customer applies the deficiency fees to
services provided or becomes unable to use the fees as payment for future services due to expiration of the contractual period the fees can be applied or
physical inability of the customer to utilize the fees due to capacity constraints. Additionally, Sunoco LP maintains some franchise agreements
requiring dealers to make one-time upfront payments for long-term license agreements. Sunoco LP recognizes a contract liability when the upfront
payment is received and recognizes revenue over the term of the license.
The following table summarizes the consolidated activity of our contract liabilities:
Balance, December 31, 2021
Additions
Revenue recognized
Other
Balance, December 31, 2022
Additions
Revenue recognized
Balance, December 31, 2023
F - 60
Contract Liabilities
459
1,113
(944)
(13)
615
1,254
(1,120)
749
$
$
Table of Contents
Index to Financial Statements
The balances of Sunoco LP’s contract assets and contract liabilities as of December 31, 2023 and 2022 were as follows:
Contract Balances
Contract assets
Accounts receivable from contracts with customers
Contract liabilities
Costs to Obtain or Fulfill a Contract
December 31,
2023
2022
$
256 $
809
—
200
834
—
Sunoco LP recognizes an asset from the costs incurred to obtain a contract (e.g. sales commissions) only if it expects to recover those costs. On the
other hand, the costs to fulfill a contract are capitalized if the costs are specifically identifiable to a contract, would result in enhancing resources that
will be used in satisfying performance obligations in the future and are expected to be recovered. These capitalized costs are recorded as a part of other
current assets and other non-current assets and are amortized on a systematic basis consistent with the pattern of transfer of the goods or services to
which such costs relate. The amount of amortization expense that Sunoco LP recognized for the years ended December 31, 2023, 2022 and 2021 was
$29 million, $22 million and $21 million, respectively. Sunoco LP has also made a policy election of expensing the costs to obtain a contract, as and
when they are incurred, in cases where the expected amortization period is one year or less.
Performance Obligations
At contract inception, the Partnership assesses the goods and services promised in its contracts with customers and identifies a performance obligation
for each promise to transfer a good or service (or bundle of goods or services) that is distinct. To identify the performance obligations, the Partnership
considers all the goods or services promised in the contract, whether explicitly stated or implied based on customary business practices. For a contract
that has more than one performance obligation, the Partnership allocates the total contract consideration it expects to be entitled to, to each distinct
performance obligation based on a standalone-selling price basis. Revenue is recognized when (or as) the performance obligations are satisfied, that is,
when the customer obtains control of the good or service. Certain of our contracts contain variable components, which, when combined with the fixed
component are considered a single performance obligation. For these types of contracts, only the fixed component of the contracts are included in the
following table.
Sunoco LP distributes fuel under long-term contracts to branded distributors, branded and unbranded third-party dealers, and branded and unbranded
retail fuel outlets. Sunoco LP branded supply contracts with distributors generally have both time and volume commitments that establish contract
duration. These contracts have an initial term of approximately ten years, with an estimated volume-weighted term remaining of approximately five
years.
Sunoco LP is party to a 15-year take-or-pay fuel supply agreement in which the distributor is required to purchase a volume of fuel that provides
Sunoco LP a minimum amount of gross profit annually. Sunoco LP expects to recognize this revenue in accordance with the contract as Sunoco LP
transfers control of the product to the customer. However, in case of annual shortfall, Sunoco LP will recognize the amount payable by the distributor
at the sooner of the time at which the distributor makes up the shortfall or becomes contractually or operationally unable to do so. The transaction price
of the contract is variable in nature, fluctuating based on market conditions. The Partnership has elected to take the practical expedient not to estimate
the amount of variable consideration allocated to wholly unsatisfied performance obligations.
In some contractual arrangements, Sunoco LP grants dealers a franchise license to operate Sunoco LP’s retail stores over the life of a franchise
agreement. In return for the grant of the retail store license, the dealer makes a one-time nonrefundable franchise fee payment to Sunoco LP plus sales
based royalties payable to Sunoco LP at a contractual rate during the period of the franchise agreement. Under the requirements of ASC Topic 606, the
franchise license is deemed to be a symbolic license for which recognition of revenue over time is the most appropriate measure of progress toward
complete satisfaction of the performance obligation. Revenue from this symbolic license is recognized evenly over the life of the franchise agreement.
F - 61
Table of Contents
Index to Financial Statements
As of December 31, 2023, the aggregate amount of transaction price allocated to unsatisfied (or partially satisfied) performance obligations was $39.10
billion, and the Partnership expects to recognize this amount as revenue within the time bands illustrated below:
Revenue expected to be recognized on
contracts with customers existing as of
December 31, 2023
$
7,590 $
6,497 $
5,769 $
19,240 $
39,096
Years Ending December 31,
2025
2024
2026
Thereafter
Total
Practical Expedients Utilized by the Partnership
The Partnership elected the following practical expedients in accordance with Topic 606:
•
•
Right to invoice: The Partnership elected to utilize an output method to recognize revenue that is based on the amount to which the Partnership has
a right to invoice a customer for services performed to date, if that amount corresponds directly with the value provided to the customer for the
related performance or its obligation completed to date. As such, the Partnership recognized revenue in the amount to which it had the right to
invoice customers.
Significant financing component: The Partnership elected not to adjust the promised amount of consideration for the effects of significant
financing component if the Partnership expects, at contract inception, that the period between the transfer of a promised good or service to a
customer and when the customer pays for that good or service will be one year or less.
• Unearned variable consideration: The Partnership elected to only disclose the unearned fixed consideration associated with unsatisfied
performance obligations related to our various customer contracts which contain both fixed and variable components.
•
•
Incremental costs of obtaining a contract: The Partnership generally expenses sales commissions when incurred because the amortization period
would have been less than one year. We record these costs within general and administrative expenses. The Partnership elected to expense the
incremental costs of obtaining a contract when the amortization period for such contracts would have been one year or less.
Shipping and handling costs: The Partnership elected to account for shipping and handling activities that occur after the customer has obtained
control of a good as fulfillment activities (i.e., an expense) rather than as a promised service.
• Measurement of transaction price: The Partnership has elected to exclude from the measurement of transaction price all taxes assessed by a
governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Partnership
from a customer (i.e., sales tax, value added tax, etc.).
•
Variable consideration of wholly unsatisfied performance obligations: The Partnership has elected to exclude the estimate of variable
consideration to the allocation of wholly unsatisfied performance obligations.
13. LEASE ACCOUNTING:
Lessee Accounting
The Partnership leases terminal facilities, tank cars, office space, land and equipment under non-cancelable operating leases whose initial terms are
typically five to 15 years, with some real estate leases having terms of 40 years or more, along with options that permit renewals for additional periods.
At the inception of each, we determine if the arrangement is a lease or contains an embedded lease and review the facts and circumstances of the
arrangement to classify lease assets as operating or finance leases under Topic 842. The Partnership has elected not to record any leases with terms of
12 months or less on our consolidated balance sheets.
At present, the majority of the Partnership’s active leases are classified as operating in accordance with Topic 842. Balances related to operating leases
are included in operating lease ROU assets, accrued and other current liabilities, operating lease current liabilities and non-current operating lease
liabilities in our consolidated balance sheets. Finance leases represent a small portion of the active lease agreements and are included in finance lease
ROU assets, current maturities of long-term debt and long-term debt, less current maturities in our consolidated balance sheets. The ROU assets
represent the Partnership’s right to use an underlying asset for the lease term and lease liabilities represent the obligation of the Partnership to make
minimum lease payments arising from the lease for the duration of the lease term.
Most leases include one or more options to renew, with renewal terms that can extend the lease term from one to 20 years or greater. The exercise of
lease renewal options is typically at the sole discretion of the Partnership and lease extensions
F - 62
Table of Contents
Index to Financial Statements
are evaluated on a lease-by-lease basis. Leases containing early termination clauses typically require the agreement of both parties to the lease. At the
inception of a lease, all renewal options reasonably certain to be exercised are considered when determining the lease term. Presently, the Partnership
does not have leases that include options to purchase or automatic transfer of ownership of the leased property to the Partnership. The depreciable life
of lease assets and leasehold improvements are limited by the expected lease term.
To determine the present value of future minimum lease payments, we use the implicit rate when readily determinable. Presently, because many of our
leases do not provide an implicit rate, the Partnership applies its incremental borrowing rate based on the information available at the lease
commencement date to determine the present value of minimum lease payments. The operating and finance lease ROU assets include any lease
payments made and exclude lease incentives.
Minimum rent payments are expensed on a straight-line basis over the term of the lease. In addition, some leases require additional contingent or
variable lease payments, which are based on the factors specific to the individual agreement. Variable lease payments the Partnership is typically
responsible for include payment of real estate taxes, maintenance expenses and insurance.
For short-term leases (leases that have term of twelve months or less upon commencement), lease payments are recognized on a straight-line basis and
no ROU assets are recorded.
The components of operating and finance lease amounts recognized in the accompanying consolidated balance sheets as of December 31, 2023 and
2022 were as follows:
Operating leases:
Lease right-of-use assets, net
Operating lease current liabilities
Accrued and other current liabilities
Non-current operating lease liabilities
Finance leases:
Property, plant and equipment, net
Lease right-of-use assets, net
Current maturities of long-term debt
Long-term debt, less current maturities
Other non-current liabilities
The components of lease expense for the years ended December 31, 2023 and 2022 were as follows:
Operating lease costs:
Operating lease cost
Operating lease cost
Operating lease cost
Total operating lease costs
Finance lease costs:
Amortization of lease assets
Interest on lease liabilities
Total finance lease costs
Short-term lease cost
Variable lease cost
Lease costs, gross
Less: Sublease income
Lease costs, net
Income Statement Location
Cost of goods sold
Operating expenses
Selling, general and administrative
Depreciation, depletion and amortization
Interest expense, net of capitalized interest
Operating expenses
Operating expenses
Other revenue
F - 63
December 31,
2023
2022
797 $
56
5
778
1 $
29
8
19
—
Year Ended December 31,
2022
2023
1 $
69
18
88
—
—
—
38
16
142
42
100 $
808
45
1
798
1
11
2
9
1
3
63
22
88
—
—
—
33
13
134
40
94
$
$
$
$
Table of Contents
Index to Financial Statements
The weighted-average remaining lease terms and weighted-average discount rates as of December 31, 2023 and 2022 were as follows:
Weighted-average remaining lease term (years):
Operating leases
Finance leases
Weighted-average discount rate (%):
Operating leases
Finance leases
December 31,
2023
2022
21
12
6 %
5 %
Cash flows and non-cash activity related to leases for the years ended December 31, 2023 and 2022 were as follows:
Operating cash flows from operating leases
Lease assets obtained in exchange for new finance lease liabilities
Lease assets obtained in exchange for new operating lease liabilities
Maturities of lease liabilities as of December 31, 2023 are as follows:
2024
2025
2026
2027
2028
Thereafter
Total lease payments
Less: present value discount
Present value of lease liabilities
Lessor Accounting
Year Ended December 31,
2022
2023
$
(139) $
18
5
Finance leases
Total
Operating leases
$
96 $
90
81
71
70
979
1,387
553
834 $
$
7 $
8
4
2
1
12
34
7
27 $
21
27
5 %
4 %
(133)
1
41
103
98
85
73
71
991
1,421
560
861
Sunoco LP leases or subleases a portion of its real estate portfolio to third-party companies as a stable source of long-term revenue. Sunoco LP’s lessor
and sublease portfolio consists mainly of operating leases with convenience store operators. At this time, most lessor agreements contain five-year
terms with renewal options to extend and early termination options based on established terms specific to the individual agreement.
Sunoco LP’s
future minimum
operating
lease
payments
receivable
as
of December
31,
2023
are
as
follows:
2024
2025
2026
2027
2028
Thereafter
Total undiscounted cash flows
F - 64
Lease Payments
$
$
108
99
82
63
38
17
407
Table of Contents
Index to Financial Statements
14. DERIVATIVE ASSETS AND LIABILITIES:
Commodity Price Risk
We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various
exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded
at fair value in our consolidated balance sheets.
We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge
inception, we lock in a margin by purchasing gas in the spot market or off-peak season and entering into a financial contract. Changes in the spreads
between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is
withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously
unrealized gains or losses associated with these positions are realized.
We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and
operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes.
We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream
segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at
market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts
are not designated as hedges for accounting purposes.
We utilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of natural gas, refined
products and NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for
accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices,
to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales. These contracts are not designated
as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our intrastate
transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have
trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of
our trading activities and the use of derivative financial instruments in our intrastate transportation and storage segment, the degree of earnings
volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of
daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and
authorizations set forth in our commodity risk management policy.
F - 65
Table of Contents
Index to Financial Statements
The following table details our outstanding commodity-related derivatives:
Mark-to-Market Derivatives
(Trading)
Natural Gas (BBtu):
(1)
Fixed Swaps/Futures
Basis Swaps IFERC/NYMEX
Swing Swaps
Options – Puts
Options - Calls
Power (Megawatt):
Forwards
Futures
Options – Puts
Crude (MBbls):
Option - Puts
Option - Calls
NGL/Refined Products (MBbls):
Option - Puts
Option - Calls
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX
Swing Swaps IFERC
Fixed Swaps/Futures
Forward Physical Contracts
NGL (MBbls) – Forwards/Swaps
Crude (MBbls) – Forwards/Swaps
Refined Products (MBbls) – Futures
Fair Value Hedging Derivatives
(Non-Trading)
Natural Gas (BBtu):
Basis Swaps IFERC/NYMEX
Fixed Swaps/Futures
Hedged Item – Inventory
December 31, 2023
December 31, 2022
Notional
Volume
Maturity
Notional
Volume
Maturity
(1,878)
(171,185)
(900)
1,900
250
155,600
(464,897)
136,000
(15)
(20)
121
(43)
124,210
(96,828)
7,125
(1,751)
(13,870)
(2,674)
(4,548)
2024-2025
2024
2024
2024
2024
2024-2029
2024
2024
2024
2024
2024-2026
2024-2026
2024-2025
2024-2025
2024-2026
2024-2026
2024-2027
2024-2025
2024-2025
145
(39,563)
—
—
—
—
(21,384)
119,200
—
—
—
—
42,440
(202,815)
(15,758)
2,423
6,934
795
(3,547)
2023
2023
—
—
—
2023-2029
2023
2023
—
—
—
—
2023-2024
2023-2024
2023-2025
2023-2024
2023-2025
2023-2024
2023-2024
(39,013)
(39,013)
39,013
2024
2024
2024
(37,448)
(37,448)
37,448
2023
2023
2023
(1)
Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub
locations.
Interest Rate Risk
We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate
debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable
rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
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Index to Financial Statements
The following table summarizes our interest rate swaps outstanding (including USAC’s), none of which were designated as hedges for accounting
purposes:
Term
Energy Transfer
July 2024
(1)
USAC
December 2025
Type
Notional Amount Outstanding
December 31, 2023 December 31, 2022
Forward-starting to pay a fixed rate of 3.388% and receive a floating rate
based on SOFR
$
— $
Pay a fixed rate of 3.9725% and receive a floating rate based on SOFR
700
400
—
(1)
The July 2024 interest rate swaps were terminated and settled in August 2023.
Credit Risk and Customers
Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have
been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies
establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial
condition of existing and potential counterparties, monitoring agency credit ratings and by implementing credit practices that limit exposure according
to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit
risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with
transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across
multiple commercial agreements with a single counterparty or affiliated group of counterparties.
Our natural gas transportation and midstream revenues are derived significantly from companies that engage in exploration and production activities.
In addition to oil and gas producers, the Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including
petrochemical companies, commercial and industrial end-users, municipalities, gas and electric utilities, midstream companies and independent power
generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to
one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a
consequence of counterparty non-performance.
The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily with independent system operators and
with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the
counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on
a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial
derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets.
For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on
our consolidated balance sheets and recognized in net income or other comprehensive income.
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Index to Financial Statements
Derivative Summary
The following table provides a summary of our derivative assets and liabilities:
Derivatives designated as hedging instruments:
Commodity derivatives (margin deposits)
Derivatives not designated as hedging instruments:
Commodity derivatives (margin deposits)
Commodity derivatives
Interest rate derivatives
Total derivatives
Fair Value of Derivative Instruments
Asset Derivatives
Liability Derivatives
December 31,
2023
December 31,
2022
December 31,
2023
December 31,
2022
$
$
51 $
51
427
132
6
565
616 $
87 $
87
506
95
—
601
688 $
(6) $
(6)
(374)
(80)
(4)
(458)
(464) $
(7)
(7)
(411)
(108)
(23)
(542)
(549)
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated
balance sheets that are subject to enforceable master netting arrangements or similar arrangements:
Balance Sheet Location
Asset Derivatives
Liability Derivatives
December 31,
2023
December 31,
2022
December 31,
2023
December 31,
2022
Derivatives without offsetting
agreements
Derivative assets (liabilities)
$
6 $
— $
(4) $
Derivatives in offsetting agreements:
OTC contracts
Broker cleared derivative
contracts
Derivative assets (liabilities)
Other current assets
(liabilities)
Offsetting agreements:
Counterparty netting
Counterparty netting
Total net derivatives
Derivative assets (liabilities)
Other current assets
(liabilities)
132
478
616
(72)
95
593
688
(85)
(80)
(380)
(464)
72
$
(368)
176 $
(359)
244 $
368
(24) $
(23)
(108)
(418)
(549)
85
359
(105)
We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value
with amounts classified as either current or long-term depending on the anticipated settlement.
F - 68
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Index to Financial Statements
The following tables summarize the amounts recognized with respect to our derivative financial instruments:
Location of Gain (Loss)
Recognized in Income on
Derivatives
Amount of Gain (Loss) Recognized in Income on
Derivatives
Years Ended December 31,
2022
2023
2021
Derivatives not designated as hedging
instruments:
Commodity derivatives – Trading
Commodity derivatives – Non-trading
Interest rate derivatives
Total
15. RETIREMENT BENEFITS:
Savings and Profit Sharing Plans
Cost of products sold
Cost of products sold
Gains (losses) on interest rate
derivatives
$
$
7 $
40
36
83 $
83 $
41
293
417 $
(6)
(141)
61
(86)
We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees,
including those of Sunoco LP and USAC. Employer matching contributions are calculated using a formula based on employee contributions. We and
our subsidiaries made matching contributions of $86 million, $79 million and $65 million to these 401(k) savings plans for the years ended December
31, 2023, 2022 and 2021, respectively.
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Index to Financial Statements
Pension and Other Postretirement Benefit Plans
Certain of the Partnership’s subsidiaries sponsor pension and/or other postretirement benefit plans that provide benefits to a defined group of retirees.
The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a
combined basis:
December 31, 2023
Pension Benefits
December 31, 2022
Pension Benefits
Funded Plans
Unfunded
Plans
Other Postretirement
Benefits
Funded Plans
Unfunded
Plans
Other Postretirement
Benefits
Change in benefit obligation:
Benefit obligation at beginning of period
$
Service cost
Interest cost
Benefits paid, net
Actuarial gain and other
Energy Transfer Canada sale
Benefit obligation at end of period
Change in plan assets:
Fair value of plan assets at beginning of
period
Return on plan assets and other
Employer contributions
Benefits paid, net
Energy Transfer Canada sale
Fair value of plan assets at end of
period
Amount underfunded (overfunded) at end of
period
Amounts recognized in the consolidated
balance sheets consist of:
Non-current assets
Current liabilities
Non-current liabilities
Amounts recognized in accumulated other
comprehensive income (pre-tax basis)
consist of:
Net actuarial gain (loss)
Prior service credit
$
$
$
$
$
22 $
—
1
(1)
1
—
23
20
2
1
(1)
—
22
19 $
—
1
(3)
—
—
17
—
—
—
—
—
—
148 $
—
6
(13)
(3)
—
138
259
29
2
(13)
—
277
50 $
—
1
(1)
(8)
(20)
22
44
(4)
1
(1)
(20)
20
26 $
—
1
(3)
(3)
(2)
19
—
—
—
—
—
—
195
1
4
(14)
(38)
—
148
311
(41)
3
(14)
—
259
1 $
17 $
(139) $
2 $
19 $
(111)
155 $
(2)
(14)
139 $
(12) $
(3)
(15) $
— $
—
(2)
(2) $
— $
—
— $
— $
(3)
(16)
(19) $
(2) $
—
(2) $
127
(2)
(14)
111
5
(3)
2
— $
—
(1)
(1) $
— $
—
— $
— $
(3)
(14)
(17) $
(2) $
—
(2) $
F - 70
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Index to Financial Statements
The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets:
December 31, 2023
Pension Benefits
December 31, 2022
Pension Benefits
Funded Plans
Unfunded Plans
Other
Postretirement
Benefits
Funded Plans
Unfunded Plans
Other
Postretirement
Benefits
Projected benefit
obligation
Accumulated benefit
obligation
Fair value of plan assets
$
23 $
23
22
Components of Net Periodic Benefit Cost
Net periodic benefit cost:
Service cost
Interest cost
Expected return on plan assets
Prior service cost amortization
Actuarial gain amortization
Net periodic benefit cost
Assumptions
15
17 $
—
N/A $
22 $
138
277
22
20
19
19 $
—
N/A
148
259
December 31, 2023
December 31, 2022
Pension Benefits
Other
Postretirement
Benefits
Pension Benefits
Other
Postretirement
Benefits
$
$
— $
1
(1)
—
—
— $
— $
6
(12)
2
(1)
(5) $
— $
2
(2)
—
—
— $
1
4
(11)
19
—
13
The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the following table:
Discount rate
December 31, 2023
December 31, 2022
Pension Benefits
Other
Postretirement
Benefits
Pension Benefits
Other
Postretirement
Benefits
2.70 %
4.62 %
5.00 %
2.46 %
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the following table:
Discount rate
Expected return on assets:
Tax exempt accounts
Taxable accounts
December 31, 2023
December 31, 2022
Pension Benefits
Other
Postretirement
Benefits
Pension Benefits
Other
Postretirement
Benefits
2.70 %
7.00 %
—
4.93 %
7.00 %
4.75 %
2.70 %
7.00 %
—
2.58 %
7.00 %
4.75 %
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved
over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed
income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer
data and historical returns are reviewed to ensure reasonableness and appropriateness.
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Index to Financial Statements
The assumed health care cost trend weighted-average rates used to measure the expected cost of benefits covered by the plans are shown in the
following table:
Health care cost trend rate
Rate to which the cost trend is assumed to decline (the ultimate trend rate)
Year that the rate reaches the ultimate trend rate
December 31,
2023
2022
7.42 %
5.17 %
2031
7.48 %
5.18 %
2030
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits.
Plan Assets
The fair value of the pension plan assets by asset category at the dates indicated is as follows:
Asset Category:
Cash and cash equivalents
Mutual funds
(1)
Total
Fair Value Total
Fair Value Measurements at December 31, 2023
Level 3
Level 2
Level 1
$
$
2 $
20
22 $
2 $
20
22 $
— $
—
— $
(1)
Comprised of approximately 100% equities as of December 31, 2023.
Asset Category:
Cash and cash equivalents
Mutual funds
(1)
Total
Fair Value Total
Fair Value Measurements at December 31, 2022
Level 3
Level 2
Level 1
$
$
2 $
18
20 $
2 $
18
20 $
— $
—
— $
(1)
Comprised of approximately 100% equities as of December 31, 2022.
The fair value of other postretirement plan assets by asset category at the dates indicated is as follows:
Asset category:
Cash and cash equivalents
(1)
Mutual funds
Fixed income securities
Total
Fair Value Total
Fair Value Measurements at December 31, 2023
Level 3
Level 2
Level 1
$
$
13 $
166
98
277 $
13 $
166
—
179 $
— $
—
98
98 $
(1)
Primarily composed of market index funds as of December 31, 2023.
Asset category:
Cash and cash equivalents
(1)
Mutual funds
Fixed income securities
Total
Fair Value Total
Fair Value Measurements at December 31, 2022
Level 3
Level 2
Level 1
$
$
19 $
146
94
259 $
19 $
146
—
165 $
— $
—
94
94 $
(1)
Primarily composed of market index funds as of December 31, 2022.
—
—
—
—
—
—
—
—
—
—
—
—
—
—
F - 72
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Index to Financial Statements
The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its
equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative
accounting guidelines.
Contributions
We expect to contribute $3 million to pension plans and $1 million to other postretirement plans in 2024. The cost of the plans are funded in
accordance with federal regulations, not to exceed the amounts deductible for income tax purposes.
Benefit Payments
The Partnership’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the
aggregate for the five years thereafter are shown in the following table:
Pension Benefits - Funded Plans
Pension Benefits - Unfunded Plans
Other Postretirement Benefits (Gross,
Before Medicare Part D)
$
2024
2025
2026
2027
2028
2029 – 2033
1 $
1
1
1
1
7
3 $
3
2
2
2
5
14
14
13
12
32
23
The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to
sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
The Partnership does not expect to receive any Medicare Part D subsidies in any future periods.
16. REPORTABLE SEGMENTS:
Our reportable segments currently reflect the following segments, which conduct their business primarily in the United States:
•
•
intrastate transportation and storage;
interstate transportation and storage;
• midstream;
• NGL and refined products transportation and services;
•
•
•
•
crude oil transportation and services;
investment in Sunoco LP;
investment in USAC; and
all other.
Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other
fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues
from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our
NGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation and other fees.
Revenues from our crude oil transportation and services segment are reflected in crude sales and gathering, transportation and other fees. Revenues
from our investment in Sunoco LP segment are primarily reflected in refined product sales. Revenues from our investment in USAC segment are
primarily reflected in gathering, transportation and other fees. Revenues from our all other segment are primarily reflected in natural gas sales.
We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as total Partnership earnings
before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as
F - 73
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Index to Financial Statements
non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and
losses on commodity risk management activities, inventory valuation adjustments, non-cash impairment charges, losses on extinguishments of debt
and other non-operating income or expense items, as well as certain non-recurring gains and losses. Inventory adjustments that are excluded from the
calculation of Adjusted EBITDA represent only the changes in lower of cost or market reserves on inventory that is carried at LIFO. These amounts
are unrealized valuation adjustments applied to Sunoco LP’s fuel volumes remaining in inventory at the end of the period. Segment Adjusted EBITDA
reflect amounts for unconsolidated affiliates based on the same recognition and measurement methods used to record equity in earnings of
unconsolidated affiliates. Adjusted EBITDA related to unconsolidated affiliates excludes the same items with respect to the unconsolidated affiliate as
those excluded from the calculation of Segment Adjusted EBITDA and consolidated Adjusted EBITDA, such as interest, taxes, depreciation,
depletion, amortization and other non-cash items. Although these amounts are excluded from Adjusted EBITDA related to unconsolidated affiliates,
such exclusion should not be understood to imply that we have control over the operations and resulting revenues and expenses of such affiliates. We
do not control our unconsolidated affiliates; therefore, we do not control the earnings or cash flows of such affiliates. The use of Segment Adjusted
EBITDA or Adjusted EBITDA related to unconsolidated affiliates as an analytical tool should be limited accordingly.
F - 74
Table of Contents
Index to Financial Statements
The following tables present financial information by segment:
Revenues:
Intrastate transportation and storage:
Revenues from external customers
Intersegment revenues
Interstate transportation and storage:
Revenues from external customers
Intersegment revenues
Midstream:
Revenues from external customers
Intersegment revenues
NGL and refined products transportation and services:
Revenues from external customers
Intersegment revenues
Crude oil transportation and services:
Revenues from external customers
Intersegment revenues
Investment in Sunoco LP:
Revenues from external customers
Intersegment revenues
Investment in USAC:
Revenues from external customers
Intersegment revenues
All other:
Revenues from external customers
Intersegment revenues
Eliminations
Total revenues
Years Ended December 31,
2022
2021
2023
$
3,222 $
740
3,962
6,954 $
864
7,818
2,328
47
2,375
2,911
7,495
10,406
18,413
3,490
21,903
26,534
2
26,536
23,026
42
23,068
824
22
846
2,185
66
2,251
4,114
12,987
17,101
21,414
4,243
25,657
25,980
2
25,982
25,677
52
25,729
689
16
705
1,328
470
1,798
(12,308)
78,586 $
2,863
711
3,574
(18,941)
89,876 $
$
F - 75
7,307
1,264
8,571
1,802
39
1,841
2,620
8,696
11,316
16,989
2,972
19,961
17,442
4
17,446
17,571
25
17,596
621
12
633
3,065
411
3,476
(13,423)
67,417
Table of Contents
Index to Financial Statements
Cost of products sold:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
Investment in Sunoco LP
Investment in USAC
All other
Eliminations
Total cost of products sold
Depreciation, depletion and amortization:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
Investment in Sunoco LP
Investment in USAC
All other
Total depreciation, depletion and amortization
Equity in earnings (losses) of unconsolidated affiliates:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
All other
Total equity in earnings of unconsolidated affiliates
Years Ended December 31,
2022
2021
2023
2,616 $
6
6,503
17,049
23,071
21,703
137
1,740
(12,284)
60,541 $
6,000 $
25
12,682
21,656
22,917
24,350
111
3,328
(18,837)
72,232 $
4,769
11
8,569
16,248
14,759
16,246
85
3,068
(13,360)
50,395
Years Ended December 31,
2022
2021
2023
214 $
563
1,451
915
740
187
246
69
4,385 $
209 $
513
1,351
865
663
193
237
133
4,164 $
Years Ended December 31,
2022
2023
2021
17 $
260
15
76
11
4
383 $
17 $
175
19
44
(2)
4
257 $
191
457
1,190
778
588
177
239
197
3,817
20
140
24
51
10
1
246
$
$
$
$
$
$
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Index to Financial Statements
Segment Adjusted EBITDA:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
Investment in Sunoco LP
Investment in USAC
All Other
Adjusted EBITDA (consolidated)
Reconciliation of net income to Adjusted EBITDA:
Net income
Depreciation, depletion and amortization
Interest expense, net of interest capitalized
Income tax expense
Impairment losses and other
Gains on interest rate derivatives
Non-cash compensation expense
Unrealized gains on commodity risk management activities
Inventory valuation adjustments
(Gains) losses on extinguishments of debt
Adjusted EBITDA related to unconsolidated affiliates
Equity in earnings of unconsolidated affiliates
Non-operating litigation-related loss
Other, net
Adjusted EBITDA (consolidated)
Segment assets:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
Investment in Sunoco LP
Investment in USAC
All other and eliminations
Total segment assets
Years Ended December 31,
2022
2021
2023
1,111 $
2,009
2,525
3,894
2,681
964
512
2
13,698 $
1,396 $
1,753
3,210
3,025
2,187
919
426
177
13,093 $
3,483
1,515
1,868
2,828
2,023
754
398
177
13,046
Years Ended December 31,
2022
2021
2023
5,294 $
4,385
2,578
303
12
(36)
130
(3)
114
(2)
691
(383)
627
(12)
13,698 $
5,868 $
4,164
2,306
204
386
(293)
115
(42)
(5)
—
565
(257)
—
82
13,093 $
6,687
3,817
2,267
184
21
(61)
111
(162)
(190)
38
523
(246)
—
57
13,046
2023
December 31,
2022
2021
6,112 $
17,708
25,592
27,214
25,464
6,826
2,737
2,045
113,698 $
6,609 $
17,979
21,851
27,903
19,200
6,830
2,666
2,605
105,643 $
7,322
17,774
21,960
28,160
19,649
5,815
2,768
2,515
105,963
$
$
$
$
$
$
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Index to Financial Statements
Additions to property, plant and equipment
(1)
:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
Investment in Sunoco LP
Investment in USAC
All other
Total additions to property, plant and equipment
(1)
Years Ended December 31,
2022
2021
2023
$
$
93 $
383
832
679
266
215
300
100
2,868 $
179 $
644
1,004
507
246
186
169
91
3,026 $
52
159
484
751
343
174
60
135
2,158
(1)
Amounts are presented on the accrual basis, net of contributions in aid of constructions costs. Amounts exclude acquisitions and include only the
Partnership’s proportionate share of capital expenditures related to joint ventures.
Investments in unconsolidated affiliates:
Intrastate transportation and storage
Interstate transportation and storage
Midstream
NGL and refined products transportation and services
Crude oil transportation and services
All other
Total investments in unconsolidated affiliates
2023
December 31,
2022
2021
$
$
144 $
2,179
141
390
187
56
3,097 $
139 $
2,201
54
398
48
53
2,893 $
110
2,209
101
457
19
51
2,947
F - 78
DESCRIPTION OF THE REGISTRANT’S SECURITIES
REGISTERED PURSUANT TO SECTION 12 OF THE
SECURITIES EXCHANGE ACT OF 1934
DESCRIPTION OF SERIES I PREFERRED UNITS
Exhibit 4.69
The following description of the Series I Preferred Units does not purport to be complete and is subject to, and qualified
in its entirety by reference to, the provisions of our Fourth Amended and Restated Agreement of Limited Partnership of Energy
Transfer LP (the “Partnership”), as amended to date (the “Partnership Agreement”), which is incorporated by reference as an
exhibit to this Annual Report on Form 10-K, of which this Exhibit is a part. We encourage you to read our Certificate of Limited
Partnership, our Partnership Agreement and the applicable provisions of the Delaware Revised Uniform Limited Partnership Act
for additional information. Capitalized terms used but not defined herein have the meanings ascribed to them in the Partnership
Agreement.
There are 41,464,179 Series I Preferred Units issued and outstanding.
General
The holders of our common units, Series I Preferred Units and other partnership securities are entitled to receive, to the
extent permitted by law and as provided in our Partnership Agreement, such distributions as may from time to time be declared
by our general partner. Upon any liquidation, dissolution or winding up of our affairs, whether voluntary or involuntary, the
holders of our common units, Series I Preferred Units and other partnership securities are entitled to receive distributions of our
assets as provided in our Partnership Agreement, after we have satisfied or made provision for our outstanding indebtedness and
other obligations and after payment to the holders of any class or series of limited partner interests having preferential rights to
receive distributions of our assets over each such class of limited partner interests.
Subject to certain liquidation rights, each Series I Preferred Unit generally has a fixed liquidation preference of $9.1273
per Series I Preferred Unit (subject to adjustment for any splits, combinations or similar adjustment to the Series I Preferred
Units) plus an amount equal to accumulated and unpaid distributions thereon to, but excluding, the date fixed for payment,
whether or not declared.
The Series I Preferred Units represent perpetual equity interests in us and, unlike our indebtedness, do not give rise to a
claim for payment of a principal amount at a particular date. As such, the Series I Preferred Units rank junior to all of our current
and future indebtedness and other liabilities with respect to assets available to satisfy claims against us. The rights of the holders
of Series I Preferred Units to receive the liquidation preference are subject to the rights of the holders of any senior securities and
the proportional rights of holders of parity securities.
All of the Series I Preferred Units are represented by one or more certificates issued to the Depository Trust Company
(“DTC”) (and its successors or assigns or any other securities
depositary selected by us) (the “Securities Depositary”) and registered in the name of its nominee, for credit to an account of a
direct or indirect participant in the Securities Depositary (including, if applicable, Euroclear and Clearstream). So long as a
Securities Depositary has been appointed and is serving, no person acquiring Series I Preferred Units is entitled to receive a
certificate representing such Series I Preferred Units unless applicable law otherwise requires or the Securities Depositary resigns
or is no longer eligible to act as such and a successor is not appointed.
We have appointed Equiniti Trust Company, LLC as the paying agent (the “Paying Agent”), and the registrar and transfer
agent (the “Registrar and Transfer Agent”), for the Series I Preferred Units.
The Series I Preferred Units, with respect to anticipated quarterly distributions and distributions upon the liquidation,
winding-up and dissolution of our affairs, rank:
Ranking
•senior to the junior securities (including our common units, Class A Units and Class B Units);
•on parity with the parity securities, including each series of our preferred units;
•junior to any senior securities; and
•junior to all of our existing and future indebtedness and other liabilities with respect to assets available to satisfy claims
against us.
Under our Partnership Agreement, we may issue junior securities from time to time in one or more series without the
consent of the holders of the Series I Preferred Units. Our general partner has the authority to determine the designations,
preferences, rights, powers, and duties of any such series before the issuance of any units of that series. Our general partner will
also determine the number of units constituting each series of securities. Our ability to issue additional parity securities in certain
circumstances or senior securities is limited as described under “-Voting Rights.”
Voting Rights
Except as set forth in our Partnership Agreement or as otherwise required by Delaware law, the Series I Preferred Units
have no voting rights.
Unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding Series I
Preferred Units, voting as a separate class, we may not adopt any amendment to our Partnership Agreement that has a material
adverse effect on the terms of the Series I Preferred Units.
In addition, unless we have received the affirmative vote or consent of the holders of at least two-thirds of the outstanding
Series I Preferred Units, voting as a class together with
holders of each series of our preferred units or other parity securities upon which like voting rights have been conferred and are
exercisable, we may not:
•create or issue any arity securities (including any additional Series I Preferred Units) if the cumulative distributions
payable on then outstanding Series I Preferred Units (or parity securities, if applicable) are in arrears; or
•create or issue any senior securities.
On any matter on which the holders of the Series I Preferred Units are entitled to vote, such holders are entitled to one
vote per Series I Preferred Unit. The Series I Preferred Units held by us or any of our subsidiaries or controlled affiliates are not
entitled to vote.
Series I Preferred Units held in nominee or street name account will be voted by the broker or other nominee in
accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee
provides otherwise.
Distributions
The Series I Preferred Units will be entitled to a cumulative distribution (the “Preferred Distribution”) of $0.2111 per quarter
in respect of each new ET preferred unit, subject to certain adjustments (as may be adjusted, the “Preferred Distribution
Amount”). Each Preferred Distribution will be paid in cash at the Preferred Distribution Amount unless, subject to certain
exceptions, (i) there is no distribution being paid on parity securities and junior securities and (ii) the Partnership’s Available
Cash, excluding any deductions to provide funds for distributions of Available Cash to the common unitholders in respect of any
one or more of the next four quarters, is insufficient to pay the Preferred Distribution. If the Partnership fails to pay the Preferred
Distribution in full in cash, then until such time as all accrued and unpaid Preferred Distributions are paid in full in cash, the
Partnership will not be permitted to declare or make (a) any distributions in respect of any junior securities (including the
common units) and (b) subject to certain exceptions, any distributions in respect of any parity securities.
If the Partnership fails to pay in full any Preferred Distribution, the amount of such unpaid distribution will accrue and
accumulate from the last day of the quarter for which such distribution is due until paid in full. Further, each Series I Preferred
Unit will have the right to share in any special distributions by the Partnership of cash, securities or other property (including in
connection with any spin-off transaction) and in the form of such cash, securities or other property pro rata with the common
units, as if the Series I Preferred Units had converted into common units at the then-applicable Conversion Ratio; provided,
however¸ that at any time there are accrued but unpaid distributions on the Preferred Units, no such special distributions will be
permitted.
Holders of Series I Preferred Units may elect (i) to convert all or any portion of such preferred units, in an aggregate
amount equaling or exceeding the Minimum Conversion Amount (as defined in the Partnership Agreement), into common units,
at the then applicable Conversion Ratio (as defined in the Partnership Agreement, initially 2.07 common units for ten Series I
Conversion
Preferred Units), subject to the payment of any accrued but unpaid distributions to the date of such conversion and (ii) in the
event of the Partnership’s voluntary liquidation, dissolution or winding up, to convert all or any portion of such Series I Preferred
Units into common units, at the then applicable Conversion Ratio, subject to payment of any accrued but unpaid distributions to
the date of conversion.
At any time, subject to certain liquidity requirements set forth in the Partnership Agreement, if the volume-weighted average
trading price of the common units on the national securities exchange on which the common units are then listed (the “VWAP
Price”) for 20 trading days over the 30-trading day period ending on the close of trading on the day immediately preceding the
date notice is given by the Partnership of election of its conversion right is greater than the quotient of (i) $13.691 divided by (ii)
the then applicable Conversion Ratio (or approximately $66.14 based on the initial Conversion Ratio), the Partnership’s general
partner, in its sole discretion, may convert all or a portion of the outstanding Series I Preferred Units into common units, at the
then applicable Conversion Ratio, subject to the payment of any accrued but unpaid distributions to the date of conversion. Also,
subject to certain liquidity requirements set forth in the Partnership Agreement, if the VWAP Price of the common units for 20
trading days over the 30-trading day period ending on the close of trading on the day immediately preceding the date notice is
given by the Partnership of the exercise of its conversion right is greater than the quotient of (i) $9.1273 divided by (ii) the then
applicable Conversion Ratio (or approximately $44.09 based on the initial Conversion Ratio), the Partnership’s general partner, in
its sole discretion, may convert all, but not less than all, of the outstanding Series I Preferred Units into a number of common
units equal to the Adjusted Conversion Amount (as defined in the Partnership Agreement).
No Sinking Fund
The Series I Preferred Units do not have the benefit of any sinking fund.
No Fiduciary Duty
We and our general partner and its officers and directors, do not owe any duties, including fiduciary duties, to holders of
the Series I Preferred Units other than an implied contractual duty of good faith and fair dealing pursuant to our Partnership
Agreement.
DESCRIPTION OF THE REGISTRANT’S SECURITIES
REGISTERED PURSUANT TO SECTION 12 OF THE
SECURITIES EXCHANGE ACT OF 1934
Description of Common Units
Exhibit 4.70
Our common units represent limited partner interests in Energy Transfer LP (the “Partnership”). Our common units entitle the holders to participate
in our cash distributions and to exercise the rights and privileges available to our limited partners under our Third Amended and Restated Agreement of
Limited Partnership, as amended to date (our “partnership agreement”). For a description of the rights of holders of our common units to cash distributions,
see the section below entitled “Distribution Policy.” For a description of the rights and privileges of limited partners under our partnership agreement,
including voting rights, see the section below entitled “Our Partnership Agreement.” We urge you to read our partnership agreement, as our partnership
agreement, and not this description, governs the rights of holders of our common units.
Number of Common Units
The majority of our common units are held by the public and the remaining are held by our affiliates. In accordance with Delaware law and the
provisions of our partnership agreement, we may issue additional common units without the approval of the then-existing holders of common units, and
such additional issuance may dilute the then-existing common unitholders percentage interests in our net assets and the voting rights of the common
unitholders under our partnership agreement.
Voting Rights
Unlike the holders of common stock in a corporation, the holders of our common units have only limited voting rights on matters affecting our
business. The holders of our common units have no right to elect the general partner or the directors of the general partner on an annual or otherwise
continuing basis. Our general partner may not be removed except by the vote of the holders of at least 66 ⁄ % of the outstanding units, including units
owned by the general partner and its affiliates. Each holder of common units is entitled to one vote for each common unit on all matters submitted to a vote
of the unitholders. Common unitholders do not have preemptive rights to acquire additional common units or other partnership securities.
2
3
Holders of Energy Transfer common units may vote on the following matters:
•
•
•
•
•
•
a sale or exchange of all or substantially all of our assets;
the election of a successor general partner in connection with the withdrawal or removal of our general partner;
dissolution or reconstitution of the Partnership;
a merger of the Partnership;
issuance of limited partner interests in some circumstances; and
some amendments to our partnership agreement, including any amendment that would cause Energy Transfer to be treated as an association
taxable as a corporation.
Removal of the general partner requires:
•
•
a 662⁄3% vote of all outstanding units; and
the election of a successor general partner by the holders of a majority of our outstanding common units.
Transfer of Energy Transfer Common Units
Any transfers of common units will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a transfer
application. By executing and delivering a transfer application, the transferee of common units:
•
•
•
•
•
becomes the record holder of the common units and is an assignee until admitted as a substituted limited partner;
automatically requests admission as a substituted limited partner;
represents and warrants that such transferee has the right, power and authority and, if an individual, the capacity to enter into our partnership
agreement;
grants the powers of attorney set forth in our partnership agreement; and
gives the consents and approvals and makes the waivers contained in our partnership agreement.
An assignee will become a substituted limited partner for the transferred common units upon the consent of our general partner and the recording of
the name of the assignee on our books and records. Our general partner may withhold its consent in its sole discretion.
A transferee’s broker, agent or nominee may complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of
common units as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result
of any agreement between the beneficial owner and the nominee holder.
Our common units are securities and are transferable according to the laws governing transfer of securities.
In addition to other rights acquired upon admission as a substituted limited partner for the transferred common units, a purchaser or transferee of our
common units who does not execute and deliver a transfer application obtains only:
•
•
the right to assign the common units to a purchaser or other transferee; and
the right to transfer the right to seek admission as a substituted limited partner for the transferred common units.
Thus, a purchaser or transferee of our common units who does not execute and deliver a transfer application:
• will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account
and the nominee or broker has executed and delivered a transfer application; and
• may not receive some federal income tax information or reports furnished to record holders of common units.
The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The
transferor does not have a duty to insure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee
neglects or chooses not to execute and forward the transfer application to the transfer agent.
Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute
owner for all purposes, except as otherwise required by law or stock exchange regulations.
Listing
Our outstanding common units are listed on the NYSE under the symbol “ET.” Any additional common units we issue also will be listed on the
NYSE.
Transfer Agent and Registrar
Our transfer agent and registrar for the common units is American Stock Transfer & Trust Company.
Our Partnership Agreement
This description is a summary of the material provisions of our partnership agreement. The provisions of our partnership agreement relating to
distributions of our available cash are described under “Distribution Policy.”
The description of our partnership agreement contained herein does not purport to be complete and is qualified in its entirety by reference to the
complete text of our Third Amended and Restated Agreement of Limited Partnership, dated February 8, 2006, as amended. A copy of our partnership
agreement is filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the SEC on February 14, 2006, as amended by Amendment No. 1 to our
partnership agreement, a copy of which is filed as Exhibit 3.3.1 to our Current Report on Form 8-K filed with the SEC on November 29, 2006, as amended
by Amendment No. 2 to our partnership agreement, a copy of which is filed as Exhibit 3.3.2 to our Current Report on Form 8-K filed with the SEC on
November 13, 2007, as amended by Amendment No. 3 to our partnership agreement, a copy of which is filed as Exhibit 3.1 to our Current Report on Form
8-K filed with the SEC on June 2, 2010, as amended by Amendment No. 4 to our partnership agreement, a copy of which is filed as Exhibit 3.1 to our
Current Report on Form 8-K filed with the SEC on December 27, 2013, as amended by Amendment No. 5 to our partnership agreement, a copy of which is
filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the SEC on March 9, 2016, as amended by Amendment No. 6 to our partnership
agreement, a copy of which is filed as Exhibit 3.2 to our Current Report on Form 8-K filed with the SEC on October 19, 2018, as amended by Amendment
No. 7 to our partnership agreement, a copy of which is filed as Exhibit 3.10 to our Quarterly Report on Form 10-Q filed with the SEC on August 8, 2019,
as amended by Amendment No. 8 to our partnership agreement, a copy of which is filed as Exhibit 3.1 to our Current Report on Form 8-K filed with the
SEC on April 1, 2021, as amended by Amendment No. 9 to our partnership agreement, a copy of which is filed as Exhibit 3.1 to our Current Report on
Form 8-K filed with the SEC on June 15, 2021, each of which is incorporated by reference into this description. We urge you to read our partnership
agreement, as our partnership agreement, and not this description, governs our partnership interests.
Purpose
Under our partnership agreement, we are permitted to engage, directly or indirectly, in any business activity that is approved by our general partner
and that lawfully may be conducted by a limited partnership organized under Delaware law, provided that our general partner may not cause us to engage,
directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or
otherwise taxable as an entity for federal income tax purposes.
Power of Attorney
Each unitholder, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if
appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution.
The power of attorney also grants the authority to amend, and to make consents and waivers under, our partnership agreement.
Distributions
Pursuant to our partnership agreement, we make quarterly distributions of available cash to all unitholders and our general partner. Please see
“Distribution Policy.”
Reimbursement of Expenses
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our
behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include
salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our
general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.
Issuance of Additional Partnership Securities; Preemptive Rights
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities and options, rights, warrants and
appreciation rights relating to the partnership securities for any partnership purpose at any time and from time to time to such persons, for such
consideration and on such terms and conditions as our general partner determines, all without the approval of any limited partners.
It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional
common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition,
the issuance of additional partnership interests may dilute (i) the percentage interests of the then-existing holders of common units in our net assets and (ii)
the voting rights of the then-existing holders of common units under our partnership agreement.
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that have
special voting rights to which the common units are not entitled.
Upon issuance of additional partnership securities, our general partner will have the right to make additional capital contributions to the extent
necessary to maintain its then-current general partner interest in us; provided, however, that the capital contributions of our general partner will be offset to
the extent contributions received by us in exchange for the issuance of additional partnership securities are used by us concurrently with such contributions
to redeem or repurchase from any person outstanding partnership securities of the same class as the partnership securities that were issued. Moreover, our
general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other
partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the
extent necessary to maintain its percentage interest, including its interest represented by common units, that existed immediately prior to each issuance.
The holders of our common units do not have preemptive rights to acquire additional common units or other partnership securities.
We also have Class A units representing limited partner interests (the “Class A units”) outstanding. The Class A units vote together with our common
units, as a single class, on any matter for which the holders of common units are entitled to vote, except as required by law. Additionally, for so long as
Kelcy Warren is an officer or a director of our general partner, upon the issuance by us of additional common units or any securities that have voting rights
that are pari passu with our common units, we will issue to the holder of Class A units a number of additional Class A units such that the holder maintains a
voting interest in us that is identical to its voting interest in us prior to such issuance. The Class A units are not entitled to distributions and otherwise have
no economic attributes, except that the Class A units in the aggregate will be entitled to an aggregate $100 distribution prior and in preference to any
distribution of assets to the holders of any other classes or series of our securities upon our liquidation, dissolution or winding up. The Class A units are not
convertible into, or exchangeable for, common units. In addition to the other voting rights of the Class A units, without the approval of 66 2/3% of the
Class A units, we may not take any action that disproportionately or materially adversely affects the rights, preferences or privileges of the Class A units or
amend the terms of the Class A units. Without the prior approval of a conflicts committee of the board of directors of our general partner, the Class A units
may not be transferred to any person or entity, other than to Kelcy Warren, Ray Davis or to any trust, family partnership or family limited liability company
the sole beneficiaries, partners or members of which are Kelcy Warren, Ray Davis or their respective relatives.
Amendments to Our Partnership Agreement
General
Amendments to our partnership agreement may be proposed only by our general partner. Our general partner has no duty or obligation to propose
any amendment to our partnership agreement and may decline to do so free of any fiduciary duty or obligation whatsoever to us, any limited partner or
assignee and, in declining to propose an amendment, is not required to act in good faith or pursuant to any other standard imposed by our partnership
agreement, any other agreement contemplated under our partnership agreement or under the Delaware Act or any other law, rule or regulation. A proposed
amendment will be effective upon its approval by the holders of a majority of the outstanding common units (a “unit majority”), unless a greater or
different percentage is required under our partnership agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of
a
specified percentage of outstanding units will be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed,
our general partner will seek the written approval of the requisite percentage of outstanding units or call a meeting of the unitholders to consider and vote
on such proposed amendment. Our general partner will notify all record holders upon final adoption of any such proposed amendments.
Restrictions on Certain Amendments
Our partnership agreement provides that:
1.
2.
3.
4.
5.
no provision of our partnership agreement that establishes a percentage of outstanding units (including units deemed owned by our general
partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of
reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of outstanding
units whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced;
no provision of our partnership agreement that establishes a percentage of outstanding units (including units deemed owned by our general
partner) required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of
reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of outstanding
units whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced;
no amendment to our partnership agreement may (a) enlarge the obligations of any limited partner without its consent, unless such shall be
deemed to have occurred as a result of an amendment approved pursuant to clause (3) below, (b) enlarge the obligations of, restrict in any way
any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, our general partner or any of its
affiliates without its consent, which consent may be given or withheld at its option, (c) change the provision of our partnership agreement
providing for our dissolution upon an election to dissolve our partnership by our general partner that is approved by a unit majority (the
“election to dissolve provision”), or (d) change the term of our partnership or, except as set forth in the election to dissolve provision, give any
person the right to dissolve our partnership;
except for mergers or consolidations approved pursuant to the partnership agreement, and without limitation of our general partner’s authority to
adopt amendments to our partnership agreement described below under “—No Unitholder Approval,” any amendment that would have a
material adverse effect on the rights or preferences of any class of partnership interests in relation to other classes of partnership interests must
be approved by the holders of not less than a majority of the outstanding partnership interests of the class affected;
except for amendments described below under “—No Unitholder Approval” and except in connection with unitholder approval of a merger or
consolidation, no amendments shall become effective without the approval of the holders of at least 90% of the outstanding units voting as a
single class unless we obtain an opinion of counsel to the effect that such amendment will not affect the limited liability of any limited partner
under applicable law; and
6.
except for amendments described below under “—No Unitholder Approval,” the provisions set forth in clauses (1) through (4) above may only
be amended with the approval of the holders of at least 90% of the outstanding units.
No Unitholder Approval
Our general partner, without the approval of any limited partner, may amend any provision of our partnership agreement to reflect:
1.
2.
a change in our name, the location of our principal place of business, our registered agent or our registered office;
admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
3.
4.
5.
6.
7.
8.
9.
a change that our general partner determines to be necessary or appropriate to qualify or continue the qualification of our partnership as a
limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the members
of the partnership group will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;
a change that our general partner determines (a) does not adversely affect the limited partners (including any particular class of partnership
interests as compared to other classes of partnership interests) in any material respect, (b) to be necessary or appropriate to (i) satisfy any
requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial
authority or contained in any federal or state statute (including the Delaware Act) or (ii) facilitate the trading of our units (including the division
of any class or classes of outstanding units into different classes to facilitate uniformity of tax consequences within such classes of units) or
comply with any rule, regulation, guideline or requirement of any national securities exchange on which the units are or will be listed for
trading, (c) to be necessary or appropriate in connection with action taken by our general partner pursuant to the provisions of our partnership
agreement governing distributions, subdivisions and combinations of partnership securities or (d) is required to effect the intent of the provisions
of our partnership agreement or is otherwise contemplated by our partnership agreement;
a change in our fiscal year or taxable year and any other changes that our general partner determines to be necessary or appropriate as a result of
a change in our fiscal year or taxable year, including, if our general partner shall so determine, a change in the definition of “Quarter” under our
partnership agreement and the dates on which distributions are to be made by us;
an amendment that is necessary, in the opinion of counsel, to prevent us, or our general partner or its directors, officers, trustees or agents from
in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as
amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether
such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;
subject to certain limitations, an amendment that our general partner determines to be necessary or appropriate in connection with the
authorization of issuance of any class or series of partnership securities pursuant to our partnership agreement;
any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
an amendment effected, necessitated or contemplated by a merger agreement approved in accordance with the provisions of our partnership
agreement;
10. an amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or investment
by us in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by us of activities
permitted by the terms of our partnership agreement;
11. a merger or conveyance pursuant to which (a) our general partner has received an opinion of counsel that the conversion, merger or conveyance,
as the case may be, would not result in the loss of the limited liability of any limited partner or any member of the partnership group or cause us
or any member of the partnership group to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal
income tax purposes (to the extent not previously treated as such), (b) the sole purpose of such conversion, merger or conveyance is to effect a
mere change in the legal form of us into another limited liability entity and (c) the governing instruments of the new entity provide the limited
partners and our general partner with the same rights and obligations as are contained in our partnership agreement; or
12. any other amendments substantially similar to the foregoing.
Withdrawal or Removal of Our General Partner
Our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ notice to our unitholders,
and that withdrawal will not constitute a breach of our partnership agreement. In addition, our partnership agreement permits our general partner in some
instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders.
If our general partner gives a notice of withdrawal, the holders of a unit majority, may, prior to the effective date of such withdrawal, elect a
successor general partner. The person so elected as successor general partner will automatically become the successor general partner or managing member,
to the extent applicable, of the other members of the partnership group of which our general partner is a general partner or a managing member. If, prior to
the effective date of our general partner’s withdrawal, a successor is not selected by our unitholders or we do not receive a withdrawal opinion of counsel
regarding limited liability and tax matters, our partnership will be dissolved in accordance with our partnership agreement.
Our general partner may be removed if such removal is approved by our unitholders holding at least 66 2/3% of the outstanding units (including units
held by our general partner and its affiliates). The right of the holders of outstanding units to remove our general partner may not be exercised unless we
have received a withdrawal opinion of counsel regarding limited liability and tax matters. The ownership of more than 33 1/3% of our outstanding units by
our general partner and its affiliates would give it the practical ability to prevent its removal.
We will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all
employee-related liabilities, including severance liabilities, incurred in connection with the termination of any employees employed by the departing
general partner or its affiliates for the benefit of us or the other members of the partnership group.
Transfer of General Partner Interest
Our general partner may transfer all or any of its general partner interest without unitholder approval. At any time, the members of our general
partner may sell or transfer all or part of their membership interests in our general partner to an affiliate or a third party without the approval of our
unitholders.
Liquidation and Distribution of Proceeds
We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:
•
•
•
•
the withdrawal, removal, bankruptcy or dissolution of our general partner, unless a successor general partner is elected prior to or on the
effective date of such withdrawal, removal, bankruptcy or dissolution and a withdrawal opinion of counsel is received by us;
an election to dissolve us by our general partner that is approved by the holders of a unit majority;
the entry of a decree of judicial dissolution of us pursuant to the provisions of the Delaware Act; or
the sale, exchange or other disposition of all or substantially all of the assets and properties of the partnership group.
Upon (a) our dissolution following the withdrawal or removal of our general partner and the failure of the partners to select a successor general
partner, then within 90 days thereafter, or (b) our dissolution upon the bankruptcy or dissolution of our general partner, then, to the maximum extent
permitted by law, within 180 days thereafter, the holders of a unit majority may elect to reconstitute us and continue our business on the same terms and
conditions set forth in our partnership agreement by forming a new limited partnership on terms identical to those set forth in our partnership agreement
and having as the successor general partner a person approved by the holders of a unit majority. Unless such an election is made within the applicable time
period as set forth above, we shall conduct only activities necessary to wind up our affairs.
Limited Call Right
If at any time our general partner and its affiliates hold more than 90% of the total limited partner interests of any class then outstanding, our general
partner will then have the right, which right it may assign and transfer in whole or in part to us or any affiliate of our general partner, exercisable at its
option, to purchase all, but not less than all, of such limited partner interests of such class then outstanding held by persons other than our general partner
and its affiliates. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price.
Indemnification
Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and
against all claims and demands whatsoever. Under our partnership agreement, in most circumstances, we will indemnify the following persons (each an
“indemnitee”) to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including
legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or
proceedings, whether civil, criminal, administrative or investigative, in which any indemnitee may be involved, or is threatened to be involved, as a party or
otherwise, by reason of its status as an indemnitee:
• our general partner;
• any departing general partner;
• any person who is or was an affiliate of our general partner or any departing general partner;
• any person who is or was a member, partner, officer, director, fiduciary or trustee of any member of the partnership group, our general partner or
any departing partner or any affiliate of any member of the partnership group, our general partner or any departing partner;
• any person who is or was serving at the request of our general partner or any departing partner or any affiliate of our general partner or any
departing partner as an officer, director, member, partner, fiduciary or trustee of another person (provided, that a person will not be an indemnitee
by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services); or
• any person that our general partner designates as an “indemnitee” for purposes of our partnership agreement.
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees in its sole discretion, our general partner will
not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, such indemnification. We may
purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power
to indemnify the person against liabilities under the partnership agreement.
Under our partnership agreement, an indemnitee will not be indemnified and held harmless if there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that, in respect of the matter for which the indemnitee is seeking indemnification pursuant to our
partnership agreement, the indemnitee acted in bad faith or engaged in fraud, willful misconduct or gross negligence or, in the case of a criminal matter,
acted with knowledge that the indemnitee’s conduct was unlawful.
In the opinion of the SEC, indemnification provisions that purport to include indemnification for liabilities arising under the Securities Act are
contrary to public policy and are, therefore, unenforceable.
Registration Rights
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any units or other
partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements
is not otherwise available. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.
General
Distribution Policy
We will distribute to our unitholders, within 50 days after the end of each quarter, all of our available cash in the manner described below.
Definition of Available Cash
Available cash generally means, for any calendar quarter, all cash on hand at the end of such quarter:
• less the amount of cash that the general partner determines in good faith is necessary or appropriate to:
▪ provide for the proper conduct of business;
▪ satisfy general, administrative and other expenses and debt service requirements;
▪ comply with applicable law, any of our debt instruments or other agreements;
▪ provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters; or
▪ provide funds for distributions on our outstanding preferred units and Class B units;
• plus all cash on hand on the date of determination of available cash for the quarter.
Distributions of Cash Upon Liquidation
If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will
first apply the proceeds of liquidation to the payment of our creditors in the order of priority provided in the partnership agreement and by law, and,
thereafter, we will distribute $100 to the holders of our Class A Units in the aggregate and any remaining proceeds to our other unitholders, including the
holders of our common units and our general partner, in accordance with their respective positive capital account balances, as adjusted to reflect any gain or
loss upon the sale or other disposition of our assets in liquidation.
No unitholder will have any obligation to restore any negative balance in its capital account upon liquidation of us.
Distributions to Preferred Unitholders
Prior to making any distributions to the unitholders as described above, the holders of our preferred units are entitled to receive, when, as, and if
declared by our general partner out of legally available funds for such purpose, cumulative quarterly cash distributions. Unless otherwise determined by our
general partner, distributions on the ET preferred units are deemed to have been paid out of available cash with respect to the quarter ended immediately
preceding the quarter in which the distribution is made.
Distributions on each class of ET preferred units are subject to an initial fixed distribution rate for a specified term, followed by a floating or reset
distribution rate, as applicable, to extend thereafter until all outstanding ET preferred units of that class are redeemed.
The 6.250% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units have an initial distribution rate of 6.250% of the
Series A liquidation preference of $1,000 per Series A preferred unit (the “Series A Liquidation Preference”) until February 14, 2023 and, thereafter,
distributions will accumulate for each distribution period at a percentage of the Series A Liquidation Preference equal to an annual floating rate of the
three-month LIBOR, or a successor rate, plus a spread of 4.028% per annum.
The 6.625% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units have an initial distribution rate of 6.625% of the
Series B liquidation preference of $1,000 per Series B preferred unit (the “Series B Liquidation Preference”) until February 14, 2028 and, thereafter,
distributions will accumulate for each distribution period at a percentage of the Series B Liquidation Preference equal to an annual floating rate of the three-
month LIBOR, or a successor rate, plus a spread of 4.155% per annum.
The 7.375% Series C Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units have an initial distribution rate of 7.375% of the
Series C liquidation preference of $25.00 per Series C preferred unit (the “Series C Liquidation Preference”) until May 14, 2023 and, thereafter,
distributions will accumulate for each distribution period at a percentage of the Series C Liquidation Preference equal to an annual floating rate of the three-
month LIBOR, or a successor rate, plus a spread of 4.530% per annum.
The 7.625% Series D Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units have an initial distribution rate of 7.625% of the
Series D liquidation preference of $25.00 per Series D preferred unit (the “Series D Liquidation Preference”) until August 14, 2023 and, thereafter,
distributions will accumulate for each distribution period at a percentage of the Series D Liquidation Preference equal to an annual floating rate of the
three-month LIBOR, or a successor rate, plus a spread of 4.738% per annum.
The 7.600% Series E Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units have an initial distribution rate of 7.600% of the
Series E liquidation preference of $25.00 per Series E preferred unit (the “Series E Liquidation Preference”) until May 15, 2024 and, thereafter,
distributions will accumulate for each distribution period at a percentage of the Series E Liquidation Preference equal to an annual floating rate of the three-
month LIBOR, or a successor rate, plus a spread of 5.161% per annum.
The 6.750% Series F Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units have an initial distribution rate of 6.750% of the Series F
liquidation preference of $1,000 per Series F preferred unit (the “Series F Liquidation Preference”) until May 15, 2025 and, thereafter, distributions will
accumulate for each distribution period at a percentage of the Series D Liquidation Preference equal to the Five-year U.S. Treasury Rate as of the most
recent Series F Reset Distribution Determination Date plus a spread of 5.134% per annum.
The 7.125% Series G Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units have an initial distribution rate of 7.125% of the Series G
liquidation preference of $1,000 per Series G preferred unit (the “Series G Liquidation Preference”) until May 15, 2030 and, thereafter, distributions will
accumulate for each distribution period at a percentage of the Series G Liquidation Preference equal to the Five-year U.S. Treasury Rate as of the most
recent Series G Reset Distribution Determination Date plus a spread of 5.306% per annum.
The 6.500% Series H Fixed-Rate Reset Cumulative Redeemable Perpetual Preferred Units have an initial distribution rate of 6.500% of the Series H
liquidation preference of $1,000 per Series H preferred unit (the “Series H Liquidation Preference”) until November 15, 2026 and, thereafter, distributions
will accumulate for each distribution period at a percentage of the Series H Liquidation Preference equal to the Five-year U.S. Treasury Rate as of the most
recent Series H Reset Distribution Determination Date plus a spread of 5.694% per annum.
The Series I Fixed-Rate Perpetual Preferred Units have a distribution rate of $0.2111 per quarter for each Series I preferred unit, subject to certain
adjustments, and a liquidation preference initially equal to $9.1273 per Series I preferred unit.
Distributions to Other Units
Our partnership agreement provides that each Class B unit is entitled to a quarterly cash distribution in an amount equal to $0.35325 per Class B unit.
If we are unable to pay the Class B unit quarterly distribution with respect to any quarter, (i) the amount of such accrued and unpaid distributions will
accumulate until paid in full in cash and (ii) the balance of such accrued and unpaid distributions shall increase at a rate of 1.5% per annum, compounded
quarterly, from the date such distribution was due until the date it is paid.
==========================================================================
AMENDED AND RESTATED ENERGY TRANSFER LP
ANNUAL BONUS PLAN
Effective as of January 1, 2023
==========================================================================
Exhibit 10.15
Annual Bonus Plan
AMENDED AND RESTATED ENERGY TRANSFER LP
ANNUAL BONUS PLAN
1. Purpose. The purpose of this Plan is to motivate management and the employees who perform services for the
Partnership and/or its affiliates and subsidiaries to earn annual cash awards through the achievement of performance
and target goals.
2. Definitions. As used in this Plan, the following terms shall have the meanings herein specified:
2.1
2.2
2.3
2.4
2.5
2.6
2.7
Actual Results means the dollar amount of Adjusted EBITDA, Distributable Cash Flow, Departmental Budget or
other applicable financial measure specified for the Budget Target(s) for a Plan Year actually achieved for such
Plan Year as determined by the Partnership following the end of such Plan Year.
Adjusted EBITDA means earnings before interest, taxes, depreciation and amortization adjusted for non-cash
compensation and extraordinary costs, including but not limited to transactional costs.
Annual Bonus means the cash bonus paid to an Eligible Employee for the Plan Year.
Annual Target Bonus means, for an Eligible Employee, a percentage of such Eligible Employee’s Eligible
Earnings, and shall be dependent on a number of factors which may include but are not limited to an employee’s
position title, job responsibilities, and reporting level within the Partnership. The Partnership may, but is not
required to, specify a specific range for an Eligible Employee at any time prior to or during a Plan Year; provided
that any such range may be adjusted from time to time or at any time in the Partnership’s sole discretion, including
for the applicable Plan Year.
Annual Target Bonus Pool means, for a Plan Year, the Target Bonus of the Eligible Employees of the Partnership
or one its employing affiliates for that Plan Year.
Board means the Board of Directors of the Company.
Bonus Pool Payout Factor means the multiplier factor applied to the Annual Target Bonus Pool to determine the
Funded Bonus Pool for the applicable Plan Year. The payout is determined by the comparison of the Budget
Target(s) for the Plan Year to Actual Results. General guidelines for the Budget Target and the Bonus Pool Payout
Factor associated with such Budget Target for a Plan Year are set forth below, but each are subject to the sole
discretion of the Compensation Committee. The Bonus Pool Payout Factor for purposes of the Plan shall be
adjusted each Plan Year based on the specific allocation of Annual Target Bonus Pools to each of the specified
Budget Target(s). Such allocations of each Budget Target to the total Annual Bonus Pool shall be determined on
an annual basis by the Compensation Committee. For 2023, the Adjusted EBITDA Budget Target shall comprise
60% of the total Annual Target Bonus Pool, the Distributable Cash Flow Budget Target shall comprise 25% of the
total Annual Target Bonus Pool and the Departmental Budget Target shall comprise the remaining 15% of the total
Annual Target Bonus Pool. While the Funded Bonus Pool will reflect an aggregation of performance under each
Bonus Pool Payout Factor the performance of Adjusted EBITDA Budget Target shall drive calculation of the Bonus
Pool, as no other targets shall be considered unless the Adjusted EBITDA Target results is at least 80% of its
Budget Target.
Annual Bonus Plan
Adjusted EBITDA Performance Target Payout Factor Guidelines
% of Budget Target
>110
107 - 110
105 – 107
103 – 105
101 – 103
95.0 - 101
90.0 – 94.9
85.0 - 89.9
80 – 84.9
< 80.0
Bonus Pool Payout Factor
1.35x
1.30x
1.25x
1.20x
1.10x
1.00X
.90x
.85x
.75x
.0x
Distributable Cash Flow Performance Target Payout Factor Guidelines
% of Budget Target
>110
107 - 110
105 – 107
103 – 105
101 – 103
95.0 - 101
90.0 – 94.9
85.0 - 89.9
80.0 – 84.9
< 80.0
Bonus Pool Payout Factor
1.35x
1.30x
1.25x
1.20x
1.10x
1.00X
.90x
.85x
.75x
.0x
Annual Bonus Plan
Departmental Budget Target Payout Factor Guidelines
% of Budget Target
0.0-101
101.0-105.9
106.0 – 110.9
111.0-114.9
>115
Bonus Pool Payout Factor
1.00x
.90x
.70x
.50x
.0x
2.8
2.9
Budget Target means the specific dollar amount of Adjusted EBITDA, Distributable Cash Flow, total Departmental
Budget and/or other financial measure(s) established by the Compensation Committee for the Partnership for a
Plan Year.
Company means LE GP, LLC, a Delaware limited liability company. The term “Company” shall include any
successor to LE GP, LLC, any subsidiary or affiliate thereof that has adopted the Plan, or any entity succeeding to
the business of LE GP, LLC, or any subsidiary or affiliate, by merger, consolidation, liquidation, or purchase of
assets or equity, or similar transaction.
2.10 Compensation Committee means the Compensation Committee of the Company’s Board.
2.11 Departmental Budget means the specific dollar amount of general and administrative expenses (i.e. operating
budget) or operating and maintenance expenses set for each department of Partnership and its subsidiaries. In
the case where a department head oversees multiple departments the Departmental Budget shall be the total
aggregate budget for all of his/her departments.
2.12 Distributable Cash Flow means net income, adjusted for certain non-cash items, less maintenance capital
expenditures.
2.13 Eligible Earnings means the aggregate regular earnings plus overtime earnings, if any, received by an Eligible
Employee during the Plan Year. For the avoidance of doubt, neither distribution payments or distribution equivalent
payments on any Partnership restricted common or restricted phantom units nor any other bonus or sign-on
payments received by an Eligible Employee during the Plan Year shall be included in the calculation of Eligible
Earnings for an Eligible Employee.
2.14 Eligible Employee has the meaning set forth in Section 4 below.
2.15
Funded Bonus Pool means the Annual Target Bonus Pool for a Plan Year multiplied by the applicable Bonus Pool
Payout Factor for such Plan Year. The establishment and amount of a Funded Bonus Pool is 100% discretionary
and subject to the final approval of and/or adjustment by the Compensation Committee. In addition, the
Compensation Committee shall have the authority to set Funded Bonus Pool above the achieved results after
calculating the Bonus Payout Factor or to set a Funded Bonus Pool below the achieved results after calculating
the Bonus Payout Factor, including a reduction to 0%.
2.16 Operational Safety Standards means the safety standards, training and requirements set forth on Exhibit A hereto,
which operations based Eligible Employees are required to comply.
Annual Bonus Plan
2.17 Partnership means Energy Transfer LP, a Delaware master limited partnership.
2.18 Person means an individual, corporation, limited liability company, partnership, joint venture, trust, unincorporated
organization, association, government agency or political subdivision thereof or other entity.
2.19 Plan means the Partnership’s Annual Bonus Plan as set forth herein, as the same may be amended from time to
time.
2.20 Plan Year means the performance (calendar) year for the measurement and determination of the Budget Target
and the calculation of Actual Results. Unless otherwise determined by the Compensation Committee, each Plan
Year shall be the one year period commencing on January 1 and ending on December 31 of the calendar year.
3. Plan Guidelines and Administration. The administration of the Plan and any determination to approve a Funded
Bonus Pool pursuant to the Plan are subject to the sole determination and discretion of the Compensation
Committee. The Compensation Committee will review the Partnership’s performance results for the designated Plan
Year, the Budget Target and Bonus Pool Payout Factor for each Plan Year and thereafter will determine, in
consultation with the Company’s Chief Executive Officer and the Company’s Chief Human Resources Officer,
whether or not and to what extent to approve the Funded Bonus Pool under the Plan. As noted in Section 2.15
above, the Committee reserves the right to determine to adjust up or down, at its discretion, the Funded Bonus Pool.
The Compensation Committee may delegate the responsibility for the administration and operation of the Plan to the
Chief Executive Officer of the Company or his/her designee(s). The Compensation Committee or the person(s) to
which administrative authority has been delegated (the Committee or such person referred to as the “Plan
Administrator”) shall have the authority to interpret and construe any and all provisions of the Plan, including the
establishment for any designated Plan Year or from time to time any Budget Targets, Budget Target guidelines,
Bonus Pool Payout Factors and/or such other economic or performance factors as the Plan Administrator shall
determine and whether and to what extent any such targets, guidelines or factors has been achieved. Any
determination made by the Plan Administrator shall be final and conclusive and binding on all persons.
4. Eligible Employees. Subject to the discretion of the Compensation Committee and such other criteria as may be
established by the Compensation Committee in general or for a particular Plan Year, all regular full-time employees
providing services to the Partnership and its subsidiaries are eligible to participate in the Annual Target Bonus Pool
for a Plan Year. No Eligible Employee shall be entitled to receive an Annual Bonus for a Plan Year unless he or she is
actively employed by the Partnership or one of its employing affiliates on the date the Annual Bonus for such Plan
Year is paid by the Company even if such payment date is after the Plan Year.
Notwithstanding the foregoing if an Eligible Employee becomes fully disabled, in the sole discretion of the
Partnership, or dies after the completion of a Plan Year but prior to the payment of the Annual Bonus, such Eligible
Employee or his/her estate, as applicable shall be eligible to receive such Eligible Employee’s Annual Bonus.
Additionally, in a situation where an Eligible Employee is displaced as a result of a transaction and such transaction
closes on or after December 31 of the Plan Year but prior to payment of the Annual Bonus, such Eligible Employee
will be able to receive a bonus award even though he/she is not employed on the date of payment of the Annual
Bonus.
Employees of Sunoco LP and its subsidiaries and USA Compression Partners, LP and its subsidiaries shall
participate in the Sunoco GP LLC Annual Bonus Plan and the USA Compression Partners, LP Amended and
Restated Annual Cash Incentive Plan, respectively and shall not be eligible to participate under this Plan.
5. Annual Bonus Payments for Eligible Employees. As soon as reasonably practicable following the end of the Plan
Year, management of the Partnership will determine the Annual Target Bonus for each Eligible Employee. The
Funded Bonus Pool from which Annual Bonuses are paid to Eligible Employees shall equal (a) the aggregate of the
Annual Target
Annual Bonus Plan
Bonuses of all Eligible Employees multiplied by (b) the Bonus Pool Payout Factor for such Plan Year, as determined
by the Compensation Committee after review of the performance results for the Plan year. The amount of the Annual
Bonus for an Eligible Employee from the Funded Bonus Pool shall be determined in management’s sole discretion
and shall be based on a number of factors including an employee’s performance, length of employment and such
other factors as may be determined by management in its sole discretion, which factors may not be the same fall all
Eligible Employees. Notwithstanding the foregoing, the Compensation Committee shall make determination of the
Annual Bonus of all of the Partnership’s named executive officers and such other executive officers as may be
determined from time to time.
In addition, operations based Eligible Employees shall be evaluated against the Operational Safety Standards set
forth on Exhibit A and any deviation or failure to meet such Operational Safety Standards may result in a reduction of
such Eligible Employee’s Annual Bonus Pool of up to 25%.
In no event, shall the aggregate amount of the Annual Bonus payments for the Plan Year exceed, in total, the Funded
Bonus Pool for such Plan Year Notwithstanding any provision herein, funds allocated under this Plan for distribution
to Eligible Employees is 100% discretionary.
Amendment and Termination. The Compensation Committee, at its sole discretion, may, without prior notice to or
consent of any Eligible Employees, amend the Plan or terminate the Plan at any time and at all times.
Indemnification. Neither the Company, the Partnership or any of its and their participating affiliates, nor the Board,
or the Compensation Committee, of the Company or any participating affiliate, nor any officer or employee of the
Company or any participating affiliate shall be liable for any act, omission, interpretation, construction or
determination made in connection with the Plan in good faith; and the members of the Company’s Board, the
Compensation Committee and/or management of the Company or the Partnership shall be entitled to indemnification
and reimbursement by the Company to the maximum extent permitted by law in respect of any claim, loss, damage
or expense (including counsel’s fees) arising from their acts, omission and conduct in their official capacity with
respect to the Plan.
6.
7.
8.
General provisions.
8.1
8.2
8.3
8.4
Non-Guarantee of Employment or Participation in the Plan. Nothing contained in this Plan shall be
construed as a contract of employment between the the Partnership and/or any of its affiliates and any
employee of the Partnership or any of its employing affiliates, and nothing in this Plan shall confer upon
any employee, including an Eligible Employee, any right to continued employment with the Partnership
and/or any of its employing affiliates, or interfere with the right of the Company, the Partnership and/or its
affiliate to terminate the employment, with or without cause, of an employee, including an Eligible
Employee. Nothing in this Plan shall give any employee any right to participate in the Plan and/or to
receive an Annual Bonus with respect to any Plan Year.
Interests Not Transferable. No right, interest or benefit under the Plan shall be subject in any manner to
alienation, sale, transfer, assignment, pledge, attachment or other legal process, or encumbrance of any
kind, and any attempt to do so shall be void.
Controlling Law. To the extent not superseded by federal law, the law of the State of Texas, without regard
to the conflicts of laws provisions thereunder, shall be controlling in all matters relating to the Plan.
Severability. If any Plan provision or any Annual Bonus award hereunder is or becomes or is deemed to
be invalid, illegal, or unenforceable in any jurisdiction or as to any person or award, or would disqualify the
Plan or any award under the law deemed applicable by the Compensation Committee, such provision
shall be
Annual Bonus Plan
construed or deemed amended to conform to the applicable laws, or if it cannot be construed or deemed
amended without, in the determination of the Compensation Committee, materially altering the intent of
the Plan or the award, such provision shall be stricken as to such jurisdiction, person or award and the
remainder of the Plan and any such award shall remain in full force and effect.
8.5
8.6
8.7
8.8
8.9
No Trust or Fund Created. Neither the Plan nor any award shall create or be construed to create a trust or
separate fund of any kind or a fiduciary relationship between the Company and its Affiliates and an
employee, including an Eligible Employee or any other person. The Plan shall constitute an unfunded
mechanism for the Company to pay bonus compensation to participants from its general assets. No
participant shall have any security or other interest in the assets of the Company.
Headings. Headings are given to the sections of the Plan solely as a convenience to facilitate reference.
Such headings shall not be deemed in any way material or relevant to the construction or interpretation of
the Plan or any provision of it.
Tax Withholding. The Partnership and/or any participating employing affiliate may deduct from any
payment otherwise due under this Plan to a Eligible Employee (or beneficiary) amounts required by law to
be withheld for purposes of federal, state or local taxes.
Off-set. The Company reserves the right to withhold any or all portions of an award or to reduce an award
to an Eligible up to an amount equal to any amount the participant owes to the Company, the Partnership
or any of its or their affiliates.
Effective Date. This Plan will be effective for the Plan Year commencing on January 1, 2023 and is
intended to replace and render null and void the Energy Transfer LP Annual Bonus Plan effective with
Plan Year 2023.
Annual Bonus Plan
EXHIBIT A
OPERATIONAL SAFETY STANDARDS
1. Satisfactory completion of all required safety training and instruction
2. Attendance at all required safety meetings
3. Avoidance of preventable vehicle incidents
4. Management discretion of overall compliance and understanding of safety standards and requirements for operation
Annual Bonus Plan
LIST OF SUBSIDIARIES
Exhibit 21.1
SUBSIDIARIES OF ENERGY TRANSFER LP, a Delaware limited partnership:
Aqua-ETC Water Solutions, LLC, a Delaware limited liability company
Arguelles Pipeline, S. De R.L. De C.V., a Mexico SRL
Arrow Field Services, LLC, a Delaware limited liability company
Arrow Midstream Holdings, LLC, a Delaware limited liability company
Arrow Pipeline, LLC, a Delaware limited liability company
Arrow Water Services LLC, a Delaware limited liability company
Arrow Water, LLC, a Delaware limited liability company
Atoka Midstream LLC, a Delaware limited liability company
Bakken Holdings Company LLC, a Delaware limited liability company
Bakken Pipeline Investments LLC, a Delaware limited liability company
Bayou Bridge Pipeline, LLC, a Delaware limited liability company
Bayview Refining Company, LLC, a Delaware limited liability company
Beartooth DevCo LLC, a Delaware limited liability company
Bighorn DevCo LLC, a Delaware limited liability company
Blue Marlin Offshore Port LLC, a Delaware limited liability company
Bobcat DevCo LLC, a Delaware limited liability company
Buckeye Products Pipe Line, L.P., a Delaware limited liability company
Buffalo Gulf Coast Terminals LLC, a Delaware limited liability company
Buffalo Parent Gulf Coast Terminals LLC, a Delaware limited liability company
Centurion Energy Transportation, LLC, a Delaware limited liability company
Centurion Permian Logistics, LLC, a Delaware limited liability company
Centurion Pipeline Company, LLC, a Delaware limited liability company
Centurion Pipeline GP, LLC, a Delaware limited liability company
Centurion Pipeline Holdco, LLC, a Delaware limited liability company
Centurion Pipeline L.P., a Delaware limited partnership
Centurion Pipeline LP I, LLC, a Delaware limited liability company
Centurion SENM Gathering, LP, a Texas limited partnership
Centurion SENM Holdings GP, LLC, a Texas limited liability company
Centurion SENM Holdings LP, LLC, a Texas limited liability company
Chalkley Gathering Company, LLC, a Texas limited liability company
Chemical Manufacturing Operations – a series of Evergreen Resources Group, LLC
Citrus ETP Finance LLC, a Delaware limited liability company
Citrus, LLC, a Delaware limited liability company
Clean Air Action Corporation, a Delaware corporation
CMLP Tres Manager LLC, a Delaware limited liability company
CMLP Tres Operator LLC, a Delaware limited liability company
Comanche Trail Pipeline, LLC, a Texas limited liability company
CPB Bowser SWD #1 LLC, a Delaware limited liability company
CPB Bowser SWD #2 LLC, a Delaware limited liability company
CPB Member LLC, a Delaware limited liability company
CPB Operator LLC, a Delaware limited liability company
CPB Subsidiary Holdings LLC, a Delaware limited liability company
CPB Transportation & Marketing LLC, a Delaware limited liability company
CPB Water LLC, a Delaware limited liability company
Crestwood Appalachia Pipeline LLC, a Texas limited liability company
Crestwood Canada Company, Nova Scotia Unlimited Company
Crestwood Corporation, a Delaware corporation
Crestwood Crude Logistics LLC, a Delaware limited liability company
Crestwood Crude Services LLC, a Delaware limited liability company
Crestwood Crude Terminals LLC, a Delaware limited liability company
Crestwood Crude Transportation LLC, a Delaware limited liability company
Crestwood Dakota Pipelines LLC, a Delaware limited liability company
Crestwood Delaware Basin LLC, a Delaware limited liability company
Crestwood Equity GP LLC, a Delaware limited liability company
Crestwood Equity Partners LP, a Delaware limited partnership
Crestwood Gas Services GP LLC, a Delaware limited liability company
Crestwood Gas Services Holdings LLC, a Delaware limited liability company
Crestwood Holdings LP, a Delaware limited partnership
Crestwood Infrastructure Holdings LLC, a Delaware limited liability company
Crestwood Marcellus Midstream LLC, a Delaware limited liability company
Crestwood Marcellus Pipeline LLC, a Delaware limited liability company
Crestwood Midstream Finance Corp., a Delaware limited liability company
Crestwood Midstream GP LLC, a Delaware limited liability company
Crestwood Midstream Operations LLC, a Delaware limited liability company
Crestwood Midstream Partners LP, a Delaware limited partnership
Crestwood New Mexico Pipeline LLC, a Texas limited liability company
Crestwood Niobrara LLC, a Delaware limited liability company
Crestwood Operations LLC, a Delaware limited liability company
Crestwood Panhandle Pipeline LLC, a Texas limited liability company
Crestwood Permian Basin Holdings LLC, a Delaware limited liability company
Crestwood Permian Basin LLC, a Delaware limited liability company
Crestwood Pipeline LLC, a Texas limited liability company
Crestwood Sales & Service LLC, a Delaware limited liability company
Crestwood Sendero GP LLC, a Delaware limited liability company
Crestwood Services LLC, a Delaware limited liability company
Crestwood Transportation LLC, a Delaware limited liability company
CrossCountry Citrus, LLC, a Delaware limited liability company
Crosspoint Pipeline, LLC, a Delaware limited liability company
Dakota Access Holdings LLC, a Delaware limited liability company
Dakota Access Truck Terminals, LLC, a Delaware limited liability company
Dakota Access, LLC, a Delaware limited liability company
DAL-TEX Consulting, LLC, a Texas limited liability company
DAPL-ETCO Construction Management, LLC, a Delaware limited liability company
DAPL-ETCO Operations Management, LLC, a Delaware limited liability company
Dual Drive Technologies, Ltd., a Texas limited partnership
E. Marcellus Asset Company, LLC, a Delaware limited liability company
Edwards Lime Gathering, LLC, a Delaware limited liability company
ELG Oil LLC, a Delaware limited liability company
ELG Utility LLC, a Delaware limited liability company
Enable Atoka, LLC, an Oklahoma limited liability company
Enable Bakken Crude Services, LLC, a Delaware limited liability company
Enable Energy Resources, LLC, an Oklahoma limited liability company
Enable Gas Transmission, LLC, a Delaware limited liability company
Enable Mississippi River Transmission, LLC, a Delaware limited liability company
Enable Natural State Pipeline, LLC, a Delaware limited liability company
Enable Oklahoma Crude Services, LLC, an Oklahoma limited liability company
Enable Oklahoma Intrastate Transmission, LLC, a Delaware limited liability company
Enable Pine Holdings, LLC, a Delaware limited liability company
Enable South Central Pipeline, LLC, a Delaware limited liability company
Enable Waskom Holdings, LLC, a Delaware limited liability company
Energy Transfer (Beijing) Energy Technology Co., Ltd., a Chinese limited liability company
Energy Transfer (R&M), LLC, a Pennsylvania limited liability company
Energy Transfer Aviation LLC, a Delaware limited liability company
Energy Transfer Crude Marketing LLC, Texas limited liability company
Energy Transfer Crude Oil Company, LLC, a Delaware limited liability company
Energy Transfer Crude Trucking LLC, Texas limited liability company
Energy Transfer Data Center, LLC, a Delaware limited liability company
Energy Transfer Employee Management LLC a Delaware limited liability company
Energy Transfer Fuel GP, LLC, a Delaware limited liability company
Energy Transfer Fuel, LP, a Delaware limited partnership
Energy Transfer GC NGL Assets GP LLC, a Delaware limited liability company
Energy Transfer GC NGL Fractionators LLC, a Delaware limited liability company
Energy Transfer GC NGL Marine Facilities LLC, a Delaware limited liability company
Energy Transfer GC NGL Marketing LLC, a Delaware limited liability company
Energy Transfer GC NGL Pipelines LP, a Delaware limited partnership
Energy Transfer GC NGL Product Services LLC, a Delaware limited liability company
Energy Transfer GC NGLs LLC, a Delaware limited liability company
Energy Transfer Geismar Olefins LLC, a Delaware limited liability company
Energy Transfer Group, L.L.C., a Texas limited liability company
Energy Transfer Hattiesburg NGLs LLC, a Delaware limited liability company
Energy Transfer International Holdings LLC, a Delaware limited liability company
Energy Transfer Interstate Holdings, LLC, a Delaware limited liability company
Energy Transfer Latin America, S. De R.L., Republic of Panama
Energy Transfer LNG Export, LLC, a Delaware limited liability company
Energy Transfer Low-Carbon Development LLC, a Delaware limited liability company
Energy Transfer Marketing & Terminals L.P., a Texas limited partnership
Energy Transfer Mexicana, LLC, a Delaware limited liability company
Energy Transfer Mont Belvieu NGL Pipelines LLC, a Delaware limited liability company
Energy Transfer Mont Belvieu NGLs GP LLC, a Delaware limited liability company
Energy Transfer Mont Belvieu NGLs LP, a Delaware limited partnership
Energy Transfer Nederland Terminal LLC, Texas limited liability company
Energy Transfer Operations GP LLC, a Delaware limited liability company
Energy Transfer Panama LLC, a Delaware limited liability company
Energy Transfer Partners, L.L.C., a Delaware limited liability company
Energy Transfer Peru 2 LLC, a Delaware limited liability company
Energy Transfer Peru S.A.C., a Peruvian Sociedad Anonima Cerrada
Energy Transfer Petrochemical Holdings, LLC, a Delaware limited liability company
Energy Transfer Retail Power, LLC, a Delaware limited liability company
Energy Transfer Sea Robin Processing LLC, a Delaware limited liability company
Energy Transfer Spindletop LLC, a Delaware limited liability company
Energy Transfer Transport, LLC, a Pennsylvania limited liability company
ET C&D Holdco LLC, a Delaware limited liability company
ET CC Holdings LLC, a Delaware limited liability company
ET COAM Holdings LLC, a Delaware limited liability company
ET CPL Holdings LLC, a Delaware limited liability company
ET Crude Oil Terminals, LLC, a Texas limited liability company
ET Crude Operating, LLC, a Delaware limited liability company
ET Finance LLC, a Delaware limited liability company
ET Gathering & Processing LLC, a Delaware limited liability company
ET Genco LLC, A Texas limited liability company
ET Insurance Canada LLC, a Delaware limited liability company
ET Intrastate Holdings LLC, a Delaware limited liability company
ET Panama Construction Company, S. de R.L., Republic of Panama ny
ET Panama Operating Company, S. de R.L., Republic of Panama
ET Procurement LLC, a Delaware limited liability company
ET Rover Pipeline LLC, a Delaware limited liability company
ET Sabina Pipeline LLC, a Texas limited liability company
ET SCOOP Express LLC, a Delaware limited liability company
ET TexLa Oasis GP LLC, a Delaware limited liability company
ETC Champ Pipeline LLC, a Delaware limited liability company
ETC China Holdings LLC, a Delaware limited liability company
ETC Compression, LLC, a Delaware limited liability company
ETC Endure Energy L.L.C., a Delaware limited liability company
ETC Fayetteville Express Pipeline, LLC, a Delaware limited liability company
ETC Fayetteville Operating Company, LLC, a Delaware limited liability company
ETC Haynesville LLC, a Delaware limited liability company
ETC Hydrocarbons, LLC, a Texas limited liability company
ETC Katy Pipeline, LLC, a Texas limited partnership
ETC Marketing, Ltd., a Texas limited partnership
ETC Midcontinent Express Pipeline, L.L.C., a Delaware limited liability company
ETC NGL Transport, LLC, a Texas limited liability company
ETC Northeast Field Services LLC, a Delaware limited liability company
ETC Northeast Pipeline, LLC, a Delaware limited liability company
ETC PennTex LLC, a Delaware limited liability company
ETC Production LLC, a Delaware limited liability company
ETC Sunoco Holdings LLC, a Pennsylvania limited liability company
ETC Texas Pipeline, Ltd., a Texas limited partnership
ETC Tiger Pipeline, LLC, a Delaware limited liability company
ETCO Holdings LLC, a Delaware limited liability company
ETE Services Company, LLC, a Delaware limited liability company
ETMT GP LLC, a Delaware limited liability company
ETP Crude LLC, a Texas limited liability company
ETP Holdco Corporation, a Delaware corporation
Everen Limited, a Bermuda limited company
Everen Specialty Ltd., a Bermuda limited company
Evergreen Assurance, LLC, a Delaware limited liability company
Evergreen Capital Holdings, LLC, a Delaware limited liability company
Evergreen Remediation Services, LLC, a Delaware limited liability company
Evergreen Resources Group, LLC, a Delaware limited liability company
Evergreen Resources Management Operations – a series of Evergreen Resources Group, LLC
Exploration & Production Operations – a series of Evergreen Resources Group, LLC
Explorer Pipeline Company, a Delaware corporation
Fayetteville Express Pipeline LLC, a Delaware limited liability company
Finger Lakes LPG Storage, LLC, a Delaware limited liability company
Florida Gas Transmission Company, LLC, a Delaware limited liability company
Gradyco Real Estate LLC, an Oklahoma limited liability company
Gulf Coast/Products GP Holdings LLC, a Delaware limited liability company
Gulf Coast Pipeline, L.P., a Delaware limited partnership
Gulf Run Transmission, LLC, a Delaware limited liability company
Helios Assurance Company, Limited, a Limited Bermuda other
HFOTCO LLC, a Texas limited liability company
Houston Pipe Line Company LP, a Delaware limited partnership
HPL Asset Holdings LP, a Delaware limited partnership
HPL GP, LLC, a Delaware limited liability company
HPL Leaseco LP, a Delaware limited partnership
HPL Resources Company LLC, a Delaware limited liability company
HPL Storage GP LLC, a Delaware limited liability company
Inland Corporation, an Ohio corporation
J.C. Nolan Pipeline Co., LLC, a Delaware limited liability company
J.C. Nolan Terminal Co., LLC, a Delaware limited liability company
Jackalope Gas Gathering Services, L.L.C. , an Oklahoma limited liability company
Japan Sun Oil Company, Ltd., a Japan other
Kanawha Rail LLC, a Delaware limited liability company
LA GP, LLC, a Texas limited liability company
La Grange Acquisition, L.P., a Texas limited partnership
Lake Charles Exports, LLC, a Delaware limited liability company
Lake Charles LNG Company, LLC, Delaware limited liability company
Lake Charles LNG Export Company, LLC, a Delaware limited liability company
LE GP Services, LLC, a Delaware limited liability company
Lee 8 Storage Partnership, a Delaware limited partnership
Legacy Refining Operations – a series of Evergreen Resources Group, LLC
LG PL, LLC, a Texas limited liability company
LGM, LLC, a Texas limited liability company
Liberty Pipeline Group, LLC, a Delaware limited liability company
Libre Insurance Company, Ltd., a Bermuda corporation
LJL, LLC, a West Virginia limited liability company
Loadout LLC, a Delaware limited liability company
Lobo Pipeline Company LLC, a Delaware limited liability company
Lotus Midstream Operations, LLC, a Delaware limited liability company
Marcus Hook Refinery Operations – a series of Evergreen Resources Group, LLC
Materials Handling Solutions LLC, a Delaware limited liability company
Maurepas Holding, LLC, an Oklahoma limited liability company
Maurepas Pipeline, LLC, a Delaware limited liability company
Mi Vida JV LLC, a Delaware limited liability company
Mid Valley Pipeline Company LLC, an Ohio limited liability company
Midcontinent Express Pipeline LLC, a Delaware limited liability company
Midwest Connector Capital Company LLC, a Delaware limited liability company
Mining Operations – a series of Evergreen Resources Group, LLC
Oasis Pipeline, LP, a Texas limited partnership
Ohio River System LLC, a Delaware limited liability company
Old Ocean Pipeline, LLC, a Texas limited liability company
Orbit Gulf Coast NGL Exports, LLC, a Delaware limited liability company
Pan Gas Storage LLC, a Delaware limited liability company
Panhandle Eastern Pipe Line Company, LP, a Delaware limited partnership
Panhandle Storage LLC, a Delaware limited liability company
Panther DevCo LLC, a Delaware limited liability company
Pelico Pipeline, LLC, a Delaware limited liability company
Penn Virginia Operating Co., LLC, a Delaware limited liability company
PEPL Real Estate, LLC, a Delaware limited liability company
Permian Express Partners LLC, a Delaware limited liability company
Permian Express Partners Operating LLC, a Texas limited liability company
Permian Express Terminal LLC, a Texas limited liability company
PG Energy LLC, a Pennsylvania limited liability company
Philadelphia Refinery Operations – a series of Evergreen Resources Group, LLC
Pine Pipeline Acquisition Company, LLC, a Delaware limited liability company
Pipe Sky, LLC, a Delaware limited liability company
Pipeline Operations – a series of Evergreen Resources Group, LLC
Powder River Basin Industrial Complex, LLC, a Delaware limited liability company
PRB HoldCo LLC, a Delaware limited liability company
Price River Terminal, LLC, a Texas limited liability company
Real Property Operations – a series of Evergreen Resource Group, LLC
Red Bluff Express Pipeline, LLC, a Delaware limited liability company
Regency Employees Management Holdings LLC, a Delaware limited liability company
Regency Energy Partners LP, a Delaware limited partnership
Regency GP LLC, a Delaware limited liability company
Regency GP LP, a Delaware limited partnership
Regency Intrastate Gas LP, a Delaware limited partnership
Regency Marcellus Gas Gathering LLC, a Delaware limited liability company
Regency Texas Pipeline LLC, a Delaware limited liability company
Retail/Service Station Operations – a series of Evergreen Resources Group, LLC
RIGS GP LLC, a Delaware limited liability company
Rose Rock Midstream Crude, LLC, a Texas limited liability company
Rough Rider Midstream Services LLC, a Delaware limited liability company
Rough Rider Operating LLC, a Delaware limited liability company
Rover Pipeline LLC, a Delaware limited liability company
RSS Water Services LLC, a Delaware limited liability company
Sea Robin Pipeline Company, LLC, a Delaware limited liability company
SEC Energy Products & Services, L.P., a Texas limited partnership
SEC General Holdings, LLC, a Texas limited liability company
SemEnergy S. de R.L. de C.V.
SemGreen, L.P., a Delaware limited partnership
SemGroup Energy S. de R.L. de C.V.
SemGroup Mexico S. de R.L. de C.V.
SemGroup Netherlands B.V., a Dutch company
SemGroup Netherlands I B.V., a Dutch company
SemManagement L.L.C., a Delaware limited liability company
SemMaterials, L.P., an Oklahoma limited partnership
SemMexico, L.L.C., an Oklahoma limited liability company
SemOperating G.P., L.L.C., an Oklahoma limited liability company
Sendero Carlsbad Finance, LLC, a Delaware limited liability company
Sendero Carlsbad Midstream, LLC, a Delaware limited liability company
Sendero Midstream Holdings, LLC, a Delaware limited liability company
Sendero Midstream Partners, LP, a Delaware limited partnership
SESH Capital, LLC, a Delaware limited liability company
SESH Sub Inc., a Delaware corporation
Southeast Supply Header, LLC, a Delaware limited liability company
Southern Union Panhandle LLC, a Delaware limited liability company
Starfish Pipeline Company, LLC, a Delaware limited liability company
Stellar Propane Service, LLC, a Delaware limited liability company
Stingray Pipeline Company, L.L.C., a Delaware limited liability company
Sun Pipe Line Company LLC, a Delaware limited liability company
Sunoco GP LLC, a Delaware limited liability company
Sunoco Logistics Partners GP LLC, a Delaware limited liability company
Sunoco LP, a Delaware limited partnership
Sunoco Partners Lease Acquisition & Marketing LLC, a Delaware limited partnership
Sunoco Pipeline L.P., a Texas limited partnership
Superfund Management Operations – a series of Evergreen Resources Group, LLC
Sweeny Gathering, L.P., a Texas limited liability company
Terminal Operations – a series of Evergreen Resources Group, LLC
TETC, LLC, a Texas limited liability company
Texas Energy Transfer Company, Ltd., a Texas limited partnership
Texas Energy Transfer Power, LLC, a Texas limited liability company
The Energy Transfer/Sunoco Foundation, a Pennsylvania non-profit
Toney Fork LLC, a Delaware limited liability company
TPL Management Operations – a series of Evergreen Resources Group, LLC
Trans-Pecos Pipeline, LLC, a Texas limited liability company
Transwestern Pipeline Company, LLC, a Delaware limited liability company
Triton Gathering, LLC, a Delaware limited liability company
Trunkline Field Services LLC, a Delaware limited liability company
Trunkline Gas Company, LLC, a Delaware limited liability company
Trunkline LNG Holdings LLC, a Delaware limited liability company
USA Compression GP, LLC, a Delaware limited liability company
USA Compression Management Services, LLC, a Delaware limited liability company
Warrior Pipeline, LLC, a Delaware limited liability company
Waskom Gas Processing Company, a Texas corporation
Waskom Transmission LLC, a Texas limited liability company
Wattenberg Holding, LLC, an Oklahoma limited liability company
West Cameron Dehydration Company, L.L.C., a Delaware limited liability company
West Shore Pipe Line Company, a Delaware corporation
West Texas Gulf Pipe Line Company LLC, a Delaware limited liability company
WGP-KHC LLC, a Delaware limited liability company
White Cliffs Pipeline, L.L.C., a Delaware limited liability company
Wink to Webster Pipeline LLC, a Delaware limited liability company
Wolverine Pipe Line Company, a Delaware corporation
Yellowstone Pipe Line Company, a Delaware corporation
SUBSIDIARIES OF SUNOCO LP, a Delaware limited partnership:
Aloha Petroleum LLC, a Delaware limited liability company
Aloha Petroleum, Ltd., a Hawaii Corporation
Eco-Products Manufacturing of Puerto Rico Inc., a Puerto Rico corporation
Fathom Global Energy FT LLC, a Delaware limited liability company
J.C. Nolan Pipeline Co., LLC, a Delaware limited liability company
J.C. Nolan Terminal Co., LLC, a Delaware limited liability company
Peerless Oil & Chemicals, Inc, a Delaware corporation
Peerless Oil Company (Puerto Rico), Inc., a Puerto Rico corporation
Petro Taino Transport Corp., a Puerto Rico corporation
Sun LP Pipeline LLC, a Delaware limited liability company
Sun LP Terminals LLC, a Delaware limited liability company
Sun Lubricants and Specialty Products Inc., a Quebec corporation
Sunmarks, LLC, a Delaware limited liability company
Sunoco Energy Solutions LLC, a Texas limited liability company
Sunoco Finance Corp., a Delaware corporation
Sunoco Global LLC, a Delaware limited liability company
Sunoco Midstream LLC, a Delaware limited liability company
Sunoco NLR LLC, a Delaware limited liability company
Sunoco Overseas, Inc., a Delaware corporation
Sunoco Refined Products LLC, a Delaware limited liability company
Sunoco Retail LLC, a Pennsylvania limited liability company
Sunoco, LLC, a Delaware limited liability company
Town & Country Food Stores, Inc., a Texas corporation
SUBSIDIARIES OF USA COMPRESSION PARTNERS, LP, a Delaware limited partnership:
USA Compression Finance Corp., a Delaware corporation
USA Compression Partners, LLC, a Delaware limited liability company
USAC Leasing, LLC, a Delaware limited liability company
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Exhibit 23.1
We have issued our reports dated February 16, 2024, with respect to the consolidated financial statements and internal control over financial reporting
included in the Annual Report of Energy Transfer LP on Form 10-K for the year ended December 31, 2023. We consent to the incorporation by reference
of said reports in the Registration Statements of Energy Transfer LP on Forms S-3 (File No. 333-228737, File No. 333-215969, File No. 333-215893, File
No. 333-146300 and File No. 333-256668), and on Forms S-8 (File No. 333-229456, File No. 333-251923, File No. 333-275904, File No. 333-275327 and
File No. 333-261502).
/s/ GRANT THORNTON LLP
Dallas, Texas
February 16, 2024
CERTIFICATION OF CO-CHIEF EXECUTIVE OFFICER
PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Marshall S. McCrea, III, certify that:
Exhibit 31.1
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Energy Transfer LP;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered
by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-
15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
b.
c.
d.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to
me by others within those entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under
my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about
the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such
evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the equivalent functions):
a.
b.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's
internal control over financial reporting.
Date: February 16, 2024
/s/ Marshall S. McCrea, III
Marshall S. McCrea, III
Co-Chief Executive Officer
CERTIFICATION OF CO-CHIEF EXECUTIVE OFFICER
PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Thomas E. Long, certify that:
Exhibit 31.2
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Energy Transfer LP;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered
by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-
15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
b.
c.
d.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to
me by others within those entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under
my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about
the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such
evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the equivalent functions):
a.
b.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's
internal control over financial reporting.
Date: February 16, 2024
/s/ Thomas E. Long
Thomas E. Long
Co-Chief Executive Officer
CERTIFICATION OF CHIEF FINANCIAL OFFICER
PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Dylan A. Bramhall, certify that:
Exhibit 31.3
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Energy Transfer LP;
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered
by this report;
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-
15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a.
b.
c.
d.
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to
me by others within those entities, particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under
my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report my conclusions about
the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such
evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's
most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is
reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5.
I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit
committee of the registrant's board of directors (or persons performing the equivalent functions):
a.
b.
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to record, process, summarize, and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's
internal control over financial reporting.
Date: February 16, 2024
/s/ Dylan A. Bramhall
Dylan A. Bramhall
Group Chief Financial Officer
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.1
In connection with the annual report of Energy Transfer LP (the “Partnership”) on Form 10-K for the year ended December 31, 2023, as filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Marshall S. McCrea, III, Co-Chief Executive Officer, certify, pursuant to 18
U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
Date: February 16, 2024
/s/ Marshall S. McCrea, III
Marshall S. McCrea, III
Co-Chief Executive Officer
A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer LP and furnished to the
Securities and Exchange Commission upon request.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.2
In connection with the annual report of Energy Transfer LP (the “Partnership”) on Form 10-K for the year ended December 31, 2023, as filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas E. Long, Co-Chief Executive Officer, certify, pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
Date: February 16, 2024
/s/ Thomas E. Long
Thomas E. Long
Co-Chief Executive Officer
A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer LP and furnished to the
Securities and Exchange Commission upon request.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
Exhibit 32.3
In connection with the annual report of Energy Transfer LP (the “Partnership”) on Form 10-K for the year ended December 31, 2023, as filed with the
Securities and Exchange Commission on the date hereof (the “Report”), I, Dylan A. Bramhall, Chief Financial Officer, certify, pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
Date: February 16, 2024
/s/ Dylan A. Bramhall
Dylan A. Bramhall
Group Chief Financial Officer
A signed original of this written statement required by Section 906 has been provided to and will be retained by Energy Transfer LP and furnished to the
Securities and Exchange Commission upon request.
ENERGY TRANSFER LP
EXECUTIVE OFFICER
INCENTIVE COMPENSATION CLAWBACK POLICY
Adopted as of November 29, 2023
Exhibit 97.1
This Executive Officer Incentive Compensation Clawback Policy (the “Policy”) has been adopted by the Compensation
Committee (the “Compensation Committee”) of the Board of Directors (the “Board”) of LE GP, LLC (the “General Partner”),
the general partner of Energy Transfer LP (together with its subsidiaries, the “Partnership”). Unless otherwise defined in this
Policy, capitalized terms shall have the meaning ascribed to such terms in Section IV.
I. Purpose
The purpose of this Policy is to enable the Partnership to recover erroneously awarded Incentive-Based Compensation
from Executive Officers in the event the Partnership is required to prepare an Accounting Restatement. This Policy is
designed to comply with, and shall be interpreted in a manner that is intended to be consistent with the requirements of
the Securities and Exchange Commission (the “SEC”) rules and the requirements of the New York Stock Exchange
(“NYSE”) Listed Company Manual.
II. Clawback of Executive Incentive Compensation
a. Recovery. In the event of an Accounting Restatement, the Administrator shall cause the Partnership to, as to any
Executive Officer who Received Incentive-Based Compensation, recover reasonably promptly the incremental
amount of Incentive-Based Compensation Received by such Executive Officer during the Relevant Recovery
Period that is in excess of the amount that would have been Received based upon the Accounting Restatement,
computed without regard to any taxes paid. For Incentive-Based Compensation based on the Partnership’s unit
price or total unitholder return, where the amount of erroneously awarded Incentive-Based Compensation is not
subject to mathematical recalculation directly from the information in the Accounting Restatement, (i) the amount
must be based on a reasonable estimate of the effect of the Accounting Restatement on the unit price or total
unitholder return upon which the Incentive-Based Compensation was Received and (ii) the Partnership shall
maintain documentation of the determination of that reasonable estimate and provide such documentation to the
NYSE. The determination of the amount of erroneously awarded Incentive-Based Compensation to be recovered
from each Executive Officer shall be determined by the Administrator. The obligation to recover erroneously
awarded Incentive-Based Compensation is not dependent on if or when restated financial statements are filed.
b. Applicability. This Policy applies to all Incentive-Based Compensation Received by an individual:
i.
After beginning service as an Executive Officer;
ii. Who served as an Executive Officer at any time during the performance period for such Incentive-Based
Compensation;
During the Relevant Recovery Period; and
On or after October 2, 2023.
iii.
iv.
III. Exceptions
a. The Administrator may determine not to seek recovery from an Executive Officer in whole or in part to the extent
it determines in its sole discretion that such recovery would be impracticable because:
i.
ii.
The direct expense paid to a third party to assist in enforcing this Policy would exceed the amount to be
recovered (after having made a reasonable attempt to recover such erroneously awarded Incentive-Based
Compensation, documenting such reasonable attempt(s) to recover, and providing that documentation to
the NYSE); or
Recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly
available to employees of the Partnership, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26
U.S.C. 411(a) and regulations thereunder.
IV. Defined Terms
a. “Accounting Restatement” means an accounting restatement required to be prepared by the Partnership due to the
material noncompliance of the Partnership with any financial reporting requirement under the securities laws,
including any required accounting restatement to correct an error in previously issued financial statements that is
material to the previously issued financial statements, or that would result in a material misstatement if the error
were corrected in the current period or left uncorrected in the current period.
b. “Accounting Restatement Date” means the earlier to occur of:
i.
ii.
The date the Board, a committee of the Board, or the officer or officers of the Partnership or General
Partner authorized to take such action if Board action is not required, concludes, or reasonably should have
concluded, that the Partnership is required to prepare an Accounting Restatement; and
The date a court, regulator, or other legally authorized body directs the Partnership to prepare an
Accounting Restatement.
c. “Administrator” means the Compensation Committee.
d. “Executive Officer” means each individual who is currently or was previously designated as on “officer” of the
Partnership as defined in Rule 16a-1(f) under the Securities Exchange Act of 1934, as amended. For the avoidance
of doubt, the identification of an Executive Officer for purposes of this Policy shall include each executive officer
who is or was identified pursuant to Item 401(b) of Regulation S-K.
e. “Financial Reporting Measure” means any measure that is determined and presented in accordance with the
accounting principles used in preparing the Partnership’s financial statements, and any other measure that is
derived wholly or in part from any such measures, including unit price and total unitholder return. A Financial
Reporting Measure is not required to be presented within the Partnership’s financial statements or included in a
filing with the SEC.
f.
“Incentive-Based Compensation” means any compensation that is granted, earned, or vested based wholly or in
part upon the attainment of a Financial Reporting Measure. Incentive-Based Compensation is deemed “Received”
in the Partnership’s fiscal period during which the Financial Reporting Measure specified in the Incentive-Based
Compensation is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end
of that period.
g. “Relevant Recovery Period” means the three completed fiscal years immediately preceding the Accounting
Restatement Date, and includes any transition period resulting from a change in the Partnership’s fiscal year
within or immediately following those three completed fiscal years (except that a transition period that comprises
a period of at least nine months shall count as a completed fiscal year).
V. Administration
a. This Policy shall be administered by the Administrator. The Administrator is authorized to interpret and construe
this Policy and to make all determinations necessary, appropriate or advisable for the administration of this Policy,
in each case, to the extent permitted under the rules and regulations issued by the SEC or the NYSE. All
determinations and decisions made by the Administrator pursuant to the provisions of this Policy shall be final,
conclusive and binding on all affected individuals.
b. The Compensation Committee may amend, supplement or modify this Policy from time to time, including to
address the requirements rules and regulations issued by the SEC or the NYSE.
VI. Prohibition of Indemnification
The Partnership is prohibited from indemnifying any Executive Officer against the loss of erroneously awarded
compensation repaid, returned or recovered pursuant to the terms of this Policy or any claims relating to the enforcement
of the Partnership’s rights under this Policy.
VII. Miscellaneous
a. The Partnership shall file all disclosures with respect to this Policy in accordance with the requirements of the
Federal securities laws, including the disclosure required by applicable SEC filings.
b. The validity, construction, and effect of the Policy and any determinations relating to the Policy shall be construed
in accordance with the laws of the State of Delaware without regard to its conflicts of laws principles. The
Administrator (and each member thereof) shall be entitled to, in good faith, rely or act upon any report or other
information furnished to him or her by any officer or employee of
the Partnership, legal counsel, independent auditors, consultants or any other agents assisting in the administration
of the Policy.
c. Any right of recovery under this Policy is in addition to, and not in lieu of, any other remedies or rights of
recovery that may be available to the Partnership under applicable law, regulation, or rule or pursuant to the terms
of any policy of the Partnership or any provision in any employment agreement, equity award agreement,
compensatory plan, agreement or other arrangement. Notwithstanding the foregoing, there shall be no duplication
of recovery of the same Incentive-Based Compensation under this Policy and any other such rights or remedies.
d. This Policy shall be binding and enforceable against all Executive Officers and their beneficiaries, heirs,
executors, administrators or other legal representatives.